(Mark One)

7 - DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criteria are accounted for on the accrual basis. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction, ~~and on~~ the nature of the hedge ~~transaction.~~transaction and hedge effectiveness.

FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the ~~second~~third quarter of 2005, FirstEnergy unwound swaps with a total notional amount of $350 million from which it received ~~$17 million in~~immaterial net cash gains. The gains will be recognized in earnings over the remaining maturity of each respective hedged security as reduced interest expense. As of ~~June~~September 30, 2005, the aggregate notional value of interest rate swap agreements outstanding was ~~$1.4~~$1.05 billion.

FirstEnergy ~~engages in hedging of~~hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings. The impact of ineffectiveness on earnings during the three months and ~~six~~nine months ended ~~June~~September 30, 2005 was not material.

During the third quarter of 2005, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the possible issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities in the second half of 2006 as outstanding debt matures. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of September 30, 2005, FirstEnergy had entered into forward swaps with an aggregate notional amount of $500 million. As of September 30, 2005 the forward swaps had a fair value of $2 million.

The net deferred ~~loss~~losses of ~~$93~~$79 million included in AOCL as of ~~June~~September 30, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million of net deferred losses, resulted from a $4$6 million ~~increase~~decrease related to current hedging activity, a $4 million increase due to the sale of gas business contracts and ~~a $7~~an $11 million decrease due to net hedge losses included in earnings during the ~~six~~nine months ended ~~June~~September 30, 2005. Approximately ~~$16~~$14 million of the net deferred ~~loss~~losses on derivative instruments in AOCL as of ~~June~~September 30, 2005 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

FirstEnergy ~~engages in the trading of~~trades commodity derivatives and periodically experiences net open positions. FirstEnergy’s risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. During the three months and ~~six~~nine months ended ~~June~~September 30, 2005, the effect of ~~discretionary~~ trading on earnings was not material.

FirstEnergy reduced the use of stock options in 2005 and increased the use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123(R) may not be representative of its future effect. FirstEnergy does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, ~~2006 (see Note 15).~~2006.

9 - ASSET RETIREMENT OBLIGATIONS

FirstEnergy has identified applicable legal obligations for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability of ~~$1.1~~$1.130 billion as of ~~June~~September 30, 2005 included ~~$1.1~~$1.115 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In the third quarter of 2005, FirstEnergy revised the ARO associated with Beaver Valley Units 1 and 2 as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million (OE - ($2) million, CEI - ($5) million, TE - ($5) million and Penn - $11 million).

The Companies maintain ~~nuclear decommissioning~~ trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of ~~June~~September 30, 2005, the fair value of the decommissioning trust assets was ~~$1.6~~$1.7 billion.

5

The following tables ~~provide the beginning and ending aggregate carrying amount of the ARO and the~~analyze changes to the ARO balance during the three months and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, respectively.

Three Months Ended	FirstEnergy		OE		CEI		TE		Penn		JCP&L		Met-Ed		Penelec		FirstEnergy			OE			CEI			TE			Penn		JCP&L			Met-Ed			Penelec
	*(In millions)*																*(In millions)*
ARO Reconciliation
Balance, April 1, 2005	$	1,095	$	204	$	276	$	198	$	141	$	74	$	135	$	67
Balance, July 1, 2005																	$	1,113		$	208		$	281		$	201		$	143	$	75		$	137		$	68
Liabilities incurred		-		-		-		-		-		-		-		-		-			-			-			-			-		-			-			-
Liabilities settled		-		-		-		-		-		-		-		-		-			-			-			-			-		-			-			-
Accretion		18		4		5		3		2		1		2		1		18			3			5			4			2		1			2			1
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-		(1	)		(2	)		(5	)		(5	)		11		-			-			-
Balance June 30, 2005	$	1,113	$	208	$	281	$	201	$	143	$	75	$	137	$	68
Balance, September 30, 2005																	$	1,130		$	209		$	281		$	200		$	156	$	76		$	139		$	69

Balance, April 1, 2004	$	1,198	$	191	$	259	$	185	$	132	$	111	$	213	$	107
Balance, July 1, 2004																	$	1,217		$	194		$	263		$	188		$	134	$	113		$	216		$	108
Liabilities incurred		-		-		-		-		-		-		-		-		-			-			-			-			-		-			-			-
Liabilities settled		-		-		-		-		-		-		-		-		-			-			-			-			-		-			-			-
Accretion		19		3		4		3		2		2		3		2		19			4			5			3			2		2			3			1
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-		(176	)		-			-			-			-		(43	)		(89	)		(44	)
Balance June 30, 2004	$	1,217	$	194	$	263	$	188	$	134	$	113	$	216	$	109
Balance, September 30, 2004																	$	1,060		$	198		$	268		$	191		$	136	$	72		$	130		$	65

The components of FirstEnergy's net periodic pension cost and other postretirement ~~benefit~~benefits cost (including amounts capitalized) for the three months and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004, consisted of the following:

Pension and postretirement benefit obligations are allocated to ~~FirstEnergy’s~~the FirstEnergy subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension ~~costs (credits)~~benefits (credit) and net periodic postretirement ~~benefit costs~~benefits (including amounts capitalized) recognized by each of the Companies in the three months and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

11 - VARIABLE INTEREST ENTITIES

~~Included in~~ FirstEnergy’s consolidated financial statements ~~are~~include PNBV and Shippingport, ~~two~~ VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of ~~$663~~$678 million, ~~$101~~$103 million and ~~$531~~$541 million, respectively, that would not be payable if the casualty value payments are made.

Income tax expenses were (increased) reduced during the three months and ~~six~~nine months ended ~~June~~September 30, 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized ~~below~~ ~~(in millions):~~below:

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of ~~June~~September 30, 2005, outstanding guarantees and other assurances aggregated approximately ~~$2.4~~$2.7 billion and included contract guarantees ($~~1.1~~1.3 billion), surety bonds ($0.3 billion) and LOCs ($~~1.0~~1.1 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. Such parental guarantees amount to ~~$0.9~~$0.8 billion (included in the ~~$1.1~~$1.3 billion discussed above) as of ~~June~~September 30, 2005 and the likelihood is remote that such guarantees will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or ~~"material~~“material adverse ~~event"~~event” the immediate posting of cash collateral or provision of aan LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of ~~June~~September 30, 2005:

Total

Collateral Paid

Remaining

Collateral Provisions

Exposure

Cash

LOC

Exposure

(In millions)

Credit rating downgrade $ 367 $ 141 $ 18 $ 208
Adverse event 50 - 7 43
Total $ 417 $ 141 $ 25 $ 251

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure
	*(In millions)*

Credit rating downgrade	$	445	$	213	$	18	$	214
Adverse event		77		-		5		72
Total	$	522	$	213	$	23	$	286

On October 3, 2005, S&P raised the senior unsecured ratings of FirstEnergy's holding company to 'BBB-' from 'BB+'. As a result of the rating upgrade, $109 million of cash collateral was subsequently returned to FirstEnergy.

9

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of ~~$296~~$307 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. ~~The following table includes information regarding the subsidiary companies and their respective financing arrangement.~~

Subsidiary Company	Parent Company		Capacity
			*(In millions)*
OES Capital, Incorporated		OE	$	170
Centerior Funding Corp.		CEI		200
Penn Power Funding LLC		Penn		25
Met-Ed Funding LLC		Met-Ed		80
Penelec Funding LLC		Penelec		75
			$	550

Financing Arrangement

Subsidiary Company

Parent Company

Borrowing Capacity

(In millions)
OES Capital, Incorporated OE $ 170
CFC CEI 200
Penn Power Funding LLC Penn 25
Met-Ed Funding LLC Met-Ed 80
Penelec Funding LLC Penelec 75
$ 550

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($47 million as of ~~June~~September 30, 2005), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future ~~change~~changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately ~~$430~~$670 million for 2005 through 2007.

The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably ~~determine~~estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report ~~that will disclose the Companies’ environmental activities, including their plans~~regarding its response to ~~respond to environmental~~air emission requirements. FirstEnergy expects to complete the report by December 1, ~~2005 and will post the report on its web site,~~ ~~www.firstenergycorp.com~~.2005.

Clean Air Act Compliance

~~The Companies are~~FirstEnergy is required to meet federally approved SO₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

~~The Companies believe they are~~FirstEnergy believes it is complying with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_x reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO_x reductions from ~~the Companies'~~FirstEnergy's facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85 percent reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO_x emissions are contributing significantly to ozone levels in the eastern United States. ~~The Companies believe their~~FirstEnergy believes its facilities are also complying with the NO_x budgets established under State Implementation Plans through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

10

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~will require~~provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂)~~. The Companies’~~ in all cases from the 2003 levels. FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas ~~our~~their New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which ~~the Companies operate~~FirstEnergy operates affected facilities.

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides a cap-and-trade program to reduce mercury emissions ~~in two phases~~ from coal-fired power ~~plants.~~plants in two phases. Initially, mercury emissions will ~~decline~~be capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO₂ and NO_xemission caps under the EPA's CAIR ~~program.~~program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. ~~The~~However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury Rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made ~~greenhouse gases~~GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic ~~greenhouse gas~~GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The ~~most significant~~other potentially material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties’ collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal Court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

14 - REGULATORY MATTERS:

Reliability Initiatives

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

EXECUTIVE SUMMARY

Net income in the ~~second~~third quarter of 2005 was ~~$178~~$332 million, or basic and diluted earnings of ~~$0.54~~$1.01 per share of common stock, compared to net income of ~~$204~~$299 million, or basic and diluted earnings of ~~$0.62~~$0.91 per share of common stock for the ~~second~~third quarter of 2004. Net income in the first ~~six~~nine months of 2005 was ~~$338~~$670 million, or basic earnings of ~~$1.03~~$2.04 per share of common stock ($~~1.02~~2.03 diluted) compared to ~~$378~~$677 million in the first ~~six~~nine months of 2004, or basic earnings of ~~$1.16~~$2.07 per share of common stock ($~~1.15~~2.06 diluted).

The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of ~~$0.05 per share~~"unusual items." Unusual items reflect the impact on earnings of ~~common stock for the quarter. Also, due to a tax law change in the State of Ohio, FirstEnergy wrote-off $72 million of net deferred tax benefits~~events that are not routine or for which management believes the financial impact will disappear or become immaterial within a near-term finite period. By removing the earnings effect of such issues that have been resolved or are expected to be ~~realized during~~resolved over the near term, management and investors can better measure FirstEnergy’s business and earnings potential. In particular, the non-core asset sales item refers to a ~~five-year phase-out period~~finite set of energy-related assets that have been previously disclosed as held for ~~Ohio income taxes. This write-off reduced second-quarter~~sale, a substantial portion of which has already been sold. In addition, as Davis-Besse restarted in 2004, further impacts from its extended outage are not expected. Similarly, further litigation settlements similar to the class action settlements in 2004 are not reasonably expected over the near term. Furthermore, FirstEnergy believes presenting normalized earnings ~~per share by $0.22.~~

~~During~~calculated in this manner provides useful information to investors in evaluating the ~~second quarter~~ongoing results of ~~2005, both~~its businesses, over the ~~Beaver Valley Unit 2~~longer term and ~~Perry stations conducted nuclear refueling outages. Perry’s outage (including an unplanned extension) began on February 22, 2005 and continued into~~assists investors in comparing FirstEnergy’s operating performance to the ~~second quarter, ending on May 6, 2005. The Beaver Valley outage began on April 4, 2005 and ended on April 28, 2005.~~operating performance of others in the energy sector.

On ~~April 21,~~October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

On September 20, 2005, FirstEnergy raised its quarterly dividend to $0.43 per share of outstanding common stock - 4.2% higher than the previous quarterly rate of $0.4125 per share. This action represents the second dividend payment increase this year. The dividend payment was last increased by 10% for the dividend paid on March 1, 2005. The new dividend is payable December 1, 2005 to shareholders of record on November 7, 2005. The Company’s dividend policy, established on November 30, 2004, targets sustainable annual dividend increases after 2005, generally reflecting an annual growth rate of 4% to 5%, and an earnings payout ratio generally within the range of 50% to 60%. The Board of Directors will continue to review the Company's dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of business conditions, results of operations, financial condition and other factors.

On September 9, 2005, FirstEnergy filed on behalf of the Ohio Companies an RCP that, if approved by the PUCO, would essentially maintain current electricity prices through 2008. The RCP was developed as a result of concerns about potential impacts to customer rates due to rising fuel prices and other factors. A stipulated agreement in support of the plan has been signed by the cities of Cleveland and Akron, along with the Industrial Energy Users - Ohio and the Ohio Energy Group. Also, the Mayor of the City of Parma has agreed to support the stipulation. The Parma City Council passed a resolution in support of the RCP plan on September 19, 2005.

During the third quarter of 2005, several FirstEnergy operating companies reached employment agreements with various local unions. On July 13, 2005, UWUA 118 and 126 - representing 445 workers - ratified an agreement with OE. On August 17, 2005, UWUA Local 180 - representing 170 workers - ratified an agreement with Penelec. On August 25, 2005, IBEW Local 1194 - representing 240 employees - ratified an agreement with OE. The collective bargaining agreement with IBEW Local 29 representing approximately 450 workers at the Beaver Valley Nuclear Power Station expired pursuant to its terms on September 30, 2005. The parties are currently negotiating a new agreement.

On September 14, 2005, FENOC announced that it ~~received a notice of violation~~would pay the $5.45 million fine proposed in April 2005 by the NRC ~~and a proposed $5.45 million fine~~ related to the reactor head ~~degradation~~issue at the Davis-Besse Nuclear Power Station. ~~The corrosion on~~FirstEnergy accrued $2.0 million of the ~~plant’s reactor head was discovered during~~fine in 2004 and the remaining amount in the first quarter of 2005. In a ~~comprehensive inspection and was reported~~letter to the NRC, ~~in March 2002. Subsequently,~~the Company noted that paying the fine brings regulatory closure to this issue and enables it to continue focusing on safe, reliable plant operations. The letter also reiterated that FENOC ~~investigated~~acknowledges full responsibility for the ~~causes of the problem, replaced~~significant performance deficiencies that led to the reactor head issue, and made numerous staff changes, as well as enhancements to plant programs and equipment. Davis-Besse has operated safely and reliably after successfully restarting in March 2004. The NRC said in a letter to FENOC that this action does not reflect the current performance of Davis-Besse and no further civil enforcement action is expected, absent any new information from the Department of Justice. On May 20, 2005, FENOC announced that it had been notified by the NRC has indicated that the ~~Davis-Besse Nuclear Power Station would return to~~cited violations regarding the standard NRC reactor oversight process, effective July 1, 2005. The NRC’s inspections of Davis-Besse are augmented to reflect commitments in a confirmatory order associated with the startup of the facility, and a previous NRC White Finding related to the performance of the emergency sirens.past plant operations do not represent current performance.

FirstEnergy announced on ~~May 18,~~September 22, 2005, that ~~it had received approval from~~FGCO plans to install an Electro-Catalytic Oxidation (ECO) system on the ~~PUCO to defer~~215-megawatt Unit 4 of its Bay Shore Plant in Oregon, Ohio. ECO is a multipollutant-control technology for ~~future recovery charges from MISO incurred~~coal-based electric utility plants that was developed by ~~FirstEnergy’s Ohio Companies. The deferred charges for 2005 are related to MISO’s administrative operation of FirstEnergy’s transmission systems and the daily and hourly spot~~Powerspan Corp., a clean energy ~~market. A request filed with the PUCO to recover these charges over~~technology company in which FirstEnergy has a ~~five-year period, beginning in 2006, is pending.~~minority ownership interest.

~~FirstEnergy’s JCP&L subsidiary announced on May 25, 2005, that~~ECO is currently being demonstrated at FGCO's R. E. Burger Plant, and has proven effective in reducing NO_x, SO₂, mercury, acid gases, and fine particulates (soot). The ECO process also produces a highly marketable ammonium sulfate fertilizer co-product, currently being sold to the NJBPU approved a stipulated agreement with the NJPBU staff and the Division of Ratepayer Advocate resolving JCP&L’s Phase II rate case filing which resulted in the one-time gain discussed above, and a second stipulated settlement agreement with the NJBPU staff resolving the motion for reconsideration of the 2003 decision in its Phase I rate proceeding.fertilizer market.

~~Together,~~FGCO expects design engineering of the ~~two stipulated settlements resulted in a net average increase, effective June 1, 2005, of approximately $1.14 per month~~Bay Shore ECO system to commence in the ~~delivery portion~~first quarter of 2006, and estimates the overall cost of the bill for residential customers using 500 KWH of electricity. The increase, averaging 2.4% per customer, is JCP&L’s first since 1993, and follows an 11% decrease implemented between 1999 and 2003 under New Jersey’s Electric Discount and Energy Competition Act. The stipulated settlements, which are expectedsystem, including a fertilizer processing plant, to ~~increase JCP&L’s annual revenues by~~be approximately ~~$51 million, include a commitment by JCP&L to maintain a target level of customer service reliability.~~

On May 27, 2005, FirstEnergy’s Ohio Companies filed with the PUCO a request to establish a generation charge adjustment factor, as permitted under the Ohio Companies’ previously approved Rate Stabilization Plan. If approved, the rider would average $0.002554 per KWH, effective January 1, 2006, for all classes of customers. The filing reflects projected increases in fuel and related costs in 2006 compared with 2002 costs.$100 million.

FIRSTENERGY’S BUSINESS

FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments.

29

·

Regulated Services transmits, distributes and sells ~~electric power~~electricity through eight ~~electric~~ utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving ~~4.4~~4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment primarily derives its revenue from the delivery of electricity, including transition cost recovery.

·

Power Supply Management Services supplies the electric power needs of end-use customers (principally in Ohio, Pennsylvania and New Jersey) through retail and wholesale arrangements, including sales to meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This business segment operates ~~the~~FirstEnergy's generating facilities ~~of the Ohio Companies and Penn~~ and purchases from the wholesale market to meet its sales obligations. Pursuant to an asset transfer on October 24, 2005, it now owns as well as operates FirstEnergy's fossil and hydroelectric generation facilities previously owned by the EUOC. It ~~leases fossil facilities from the EUOC and~~also purchases the entire output of the ~~EUOC~~ nuclear ~~plants.~~plants currently owned or leased by the EUOC. This business segment principally derives its revenues from electric generation sales.

Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy ~~continues to divest these~~is in the process of divesting non-core businesses. See Note 6 to the consolidated financial statements. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as ~~"reportable segments"~~“reportable segments”.

On May 13, 2005, Penn, and on May 18, 2005 ~~OE, CEI and TE,~~the Ohio Companies, entered into certain agreements ~~described below (Agreements)~~ implementing a series of intra-system generation asset transfers. When ~~concluded,~~fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear ~~fossil~~ and ~~hydroelectric~~non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to the May 13 and May 18, 2005 agreements and FGCO's purchase option under the Master Facility Lease.

As contemplated by the agreements entered into in May 2005, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC currently operates and maintains the nuclear generation assets to be transferred. FirstEnergy currently expects to complete the nuclear asset transfers in the fourth quarter of 2005, subject to the receipt of required regulatory approvals.

These transactions are ~~being undertaken in connection with~~pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO ~~respectively,~~ without impacting the operation of the plants.

Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.

33

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among ~~our~~FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 16 to the consolidated financial statements. The FSG business segment is included in ~~"Other~~“Other and Reconciling ~~Adjustments"~~Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 16 to the consolidated financial statements. Net income (loss) by major business segment ~~was~~is as follows:

Earnings in the second quarter of 2005 included a net gain resulting from the JCP&L rate settlement of $16 million (or $0.05 per share) and additional income tax expense of $72 million (or $0.22 per share) from the enactment of new Ohio tax legislation. This compares to the second quarter of 2004 which included a loss from the sale of GLEP of approximately $7 million ($0.02 per share) and a litigation settlement loss of $11 million ($0.03 per share). In addition to the second quarter items, netNet income in the ~~first six~~regulated services segment for the three months and nine months ended September 30, 2005 increased due to additional customer demand. However, net income for the power supply management services segment was lower in both the three months and nine months ended September 30, 2005 compared to the same periods in 2004, as a result of ~~2005 included $22 million ($0.07 per share) of gains~~higher costs for fossil fuel, purchased power (excluding 2004 PJM transactions on a gross basis) and nuclear refueling costs which, in aggregate, more than offset the revenue from ~~the disposition of non-core assets, an EPA settlement loss of $14 million ($0.04 per share) and an NRC fine of $3 million ($0.01 per share).~~increased electric generation sales.

A decrease in wholesale electric revenues and purchased power costs in the ~~second quarter and first six months of~~ 2005 ~~from~~periods compared to the corresponding periods last year primarily resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in ~~the same period of 2004.~~2004 (See Note 2 - Accounting for Wholesale Energy Transactions). This change had no impact on earnings and resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM in January 2005. FirstEnergy believes that a net-hourly-position measure of revenues and purchased power transactions is required as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the ~~second quarter of~~three months and nine months ended September 30, 2004 each included ~~$283~~additional amounts of $264 million ~~from these~~and $828 million, respectively, due to recording those transactions ~~recorded~~ on a gross ~~basis — the first six months of 2004 included $564 million from these transactions.~~basis.

Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, total operating revenues in the ~~second quarter~~three months and ~~first six~~nine months ofended September 30, 2005 increased 14.9% and 8.7%, respectively, reflecting in large part warmer than normal temperatures induring the second quarter of 2005. Net income in the regulated services segment increased due to the additional demand. However, net income for the power supply management services segment was lower in both the second quarter and first six monthssummer of 2005 as a result of higher costs for fossil fuel, purchased power and nuclear refueling costs which, in aggregate, more than offset the revenue from increased electric generation sales. The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.compared to 2004.

Increased consumption offset in part by lower composite prices to customers resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the ~~$40~~$123 million increase in distribution services revenue in the ~~second~~third quarter of 2005:

33

	Increase			Increase
Sources of Change in Distribution Revenues	(Decrease)			(Decrease)
	*(In millions)*			*(In millions)*

Changes in customer usage	$	52		$	135
Changes in prices:
Rate changes --
Ohio shopping incentive		(11	)
Other		(1	)
Ohio shopping credits					(11	)
JCP&L rate settlements					21
Billing component reallocations					(22	)
Net Increase in Distribution Revenues	$	40		$	123

Distribution revenues benefited from warmer ~~than normal~~summer temperatures in the ~~second~~third quarter of 2005, compared to 2004, that increased the air-conditioning load of residential and commercial customers. ~~Reduced~~While industrial ~~demand as a result of a softening in the automotive and steel-related sectors~~deliveries also increased, that impact was more than offset ~~part of the weather-induced increase in load. A reduction in~~by lower unit prices ~~primarily resulted~~to that sector. Higher base rates from JCP&L's stipulated rate settlements were more than offset by additional credits provided to customers under the Ohio transition plan ~~- those changes~~and a reallocation of billing components primarily related to special contracts. Shopping credits do not affect current period earnings due to deferral of the incentives for future recovery from customers.

Transmission revenues increased ~~$40~~$36 million in the ~~second~~third quarter of 2005 from the same period last year due in part to ~~an amended power supply agreement with FES in June 2004.~~increased loads due to warmer weather and higher transmission usage prices. Other revenues ~~decreased $7~~increased $35 million primarily due ~~in part~~ to ~~a reduction in JCP&L transition bond revenues.~~higher gains realized on nuclear decommissioning trust investments.

Expenses-

The ~~higher~~increase in total revenues discussed above ~~were~~was partially offset by the following increases in total expenses:

·~~Higher~~Other operating expenses increased by $97 million in the third quarter of 2005 compared to the same

period in 2004 primarily due to increased transmission expenses ~~of $42 million due~~resulting in part ~~to an amended power supply agreement with FES, which also~~from increased ~~revenue;~~loads

and higher transmission system usage charges;

·Increased provision for depreciation of $8 million ~~due to~~that resulted from property ~~additions;~~additions and increased

leasehold improvement amortization;

·Additional amortization of regulatory assets of ~~$36~~$40 million, principally ~~due to increased amortization of~~ Ohio transition costs;

·

~~Increased~~

Higher general taxes of ~~$14~~$9 million ~~due to additional~~resulting from increased EUOC sales which increased the Ohio KWH

tax and the Pennsylvania gross receipts ~~tax and the absence in 2005 of Pennsylvania property tax refunds recognized in the second quarter of 2004; and~~tax;

·Increased interest charges of $6 million primarily due to the absence of $11 million in interest rate swap

savings achieved in the third quarter of 2004; and

· Higher income taxes of ~~$15~~$28 million due to increased taxable income.

Partially offsetting ~~these higher costs were two factors:~~

·~~Additional deferral~~those increases was the effect of additional deferred regulatory assets of ~~$52~~$45 million, primarily due to the PUCO-approved deferral of MISO administrative costs, ~~JCP&L reliability improvements~~shopping incentives and related ~~interest (see Note 14 - Regulatory Matters - Transmission; New Jersey); and~~

·~~Lower interest charges of $14 million resulting from debt and preferred stock redemptions and refinancings.~~interest.

Power Supply Management Services - ~~Second~~Third Quarter 2005 Compared with ~~Second~~Third Quarter 2004

Net income for this segment decreased $34 million to ~~$11~~$10 million in the ~~second~~third quarter of 2005 from ~~$37~~$44 million in the same period last ~~year. A~~year, due to a decrease in the gross generation margin and higher ~~non-fuel nuclear costs resulted in lower net income.~~operating costs.

3437

~~Generation Margin -~~

~~The gross generation margin in the second quarter of 2005 decreased by $44 million compared to the same period of 2004, as shown in the table below.~~

Three Months Ended

June 30,

Gross Generation Margin

2005

2004

(Decrease)

(In millions)

Electric generation revenue $ 1,314 $ 1,520 $ (206 )
Fuel and purchased power costs 933 1,095 (162 )
Gross generation margin $ 381 $ 425 $ (44 )

Excluding the effect of recording PJM sales and purchases of $283 million on a gross basis in 2004, electric generation revenues increased $77 million while fuel and purchased power costs increased $121 million in the second quarter of 2005. The higher fuel and purchased power costs primarily resulted from higher prices which more than offset the benefit of increased sales to the retail and wholesale markets.

Revenues -

Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($264 million), electric generation revenues increased ~~$77~~$227 million in the ~~second~~third quarter of 2005 compared to the same period of 2004 primarily as a result of a ~~1.5%~~5.2% increase in KWH sales due to higher retail customer usage and ~~higher~~a 21% rise in unit ~~prices.~~prices in the wholesale market. The ~~additional~~increase in retail sales reduced energy available for sale to the wholesale market, resulting in a ~~0.9%~~9% reduction in ~~those~~wholesale sales (before the PJM adjustment). ~~Overall, revenues to the wholesale market increased due to a 7% rise in prices.~~

The change in reported segment revenues resulted from the following:

The following ~~sources:~~table summarizes the price and volume factors contributing to increased sales to retail and wholesale customers.

Excluding the effect of ~~the $283~~$264 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by ~~$138~~$254 million in the ~~second~~third quarter of 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed ~~$121~~$2 million ($~~162~~266 million, net of ~~$283~~$264 million PJM effect) of the increase, resulting from higher fuel costs of ~~$89~~$121 million and increased purchased power costs of ~~$32~~$145 million. Factors contributing to the higher costs are summarized in the following table:

Increase

Source of Change in Fuel and Purchased Power

(Decrease)

(In millions)

Fuel:
Change due to price
$ 65
Change due to volume
24
89
Purchased Power:
Change due to price
64
Change due to volume
(9 )
Deferred costs
(23 )
32

Net Increase in Fuel and Purchased Power Costs $ 121

FirstEnergy’s generation fleet ~~of generating plants~~ established ~~a new~~an output record of ~~19.1~~21.7 billion ~~KWH. Increased~~KWH in the third quarter of 2005. As a result, increased coal consumption and the related cost of emission ~~allowance costs~~allowances combined to increase fossil fuel expense. Higher coal costs resulted from increased market purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to higher costs associated with the ~~increased mix of fossil versus nuclear~~increase in generation ~~resulting in large part~~ from the fossil units relative to nuclear ~~refueling outages~~generation. Fossil generation output increased 16% in the ~~second quarter of 2005 following a year with no scheduled nuclear outages. Fossil generation increased 12% in the second~~third quarter of 2005 while nuclear ~~generation decreased~~output increased by ~~16%.~~

~~Partially offsetting these~~Other operating costs increased $8 million in the third quarter of 2005 compared to the same period of 2004. This increase resulted from higher transmission costs due primarily to increased loads and higher transmission system usage charges. The higher costs this year were offset in part by lower non-fuel nuclear costs resulting from expenses incurred late in the ~~following factors:~~third quarter of 2004 in preparation for the fourth quarter of 2004 Beaver Valley Unit 1 refueling outage.

·~~Reduced non-fuel fossil generation expense of $7 million due to different maintenance outage schedules;~~

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net ~~decrease~~increase of $16 million in ~~FirstEnergy’s~~ net income in the ~~second~~third quarter of 2005 compared to the same quarter of 2004. The ~~decrease~~increase was primarily due to the absence this year of losses recognized in 2004 on the sale of securities and impairment of several partnership investments.

Cash Flows From Financing Activities

In the ~~second~~third quarter and first ~~six~~nine months of 2005, cash used for financing activities was ~~$109~~$580 million and ~~$468 million,~~$1.0 billion, respectively, compared to ~~$573~~$602 million and ~~$813 million~~$1.4 billion in the ~~second~~third quarter and first ~~six~~nine months of 2004, respectively. The following table summarizes security issuances and redemptions.

FirstEnergy had approximately ~~$555~~$247 million of short-term indebtedness as of ~~June~~September 30, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowings as of ~~June~~September 30, 2005 included the following:

As of ~~June 30,~~October 24, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately ~~$4.1~~$3.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage ~~indentures.~~indentures following the recently completed intra-system transfer of fossil and hydroelectric generating plants (See Note 17). The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to ~~$668~~$690 million and ~~$570~~$582 million, respectively, as of ~~June 30,~~October 24, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of ~~June 30,~~October 24, 2005, JCP&L had the capability to issue ~~$597~~$673 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of ~~$4.3~~$4.9 billion of preferred stock (assuming no additional debt was issued) as of ~~June~~September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil and hydroelectric generating plants will reduce the aggregate capability of OE, Penn, TE and JCP&L to issue preferred stock by approximately 10%. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.

As of ~~June~~September 30, 2005, approximately $1 billion remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

FirstEnergy’s and its subsidiaries' working capital and short-term borrowing needs are met principally with a $2 billion five-year revolving credit facility that was entered into on June 14, 2005 by FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, with a syndicate of banks. The facility replaced FirstEnergy’s $375 million and $1 billion three-year credit agreements, OE’s $125 million three-year credit agreement and OE’s recently-expired $250 million two-year credit agreement.(included in the table above). Borrowings under the facility are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date.

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations.

⁽¹⁾As of ~~June~~September 30, 2005.

The revolving credit facility, combined with an aggregate $550 million ($395 million unused as of September 30, 2005) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.

As of ~~June~~September 30, 2005, FirstEnergy and ~~it’s~~ subsidiaries’ ~~fixed charge coverage ratios,~~debt to total capitalization as defined under the revolving credit ~~agreements,~~facility, were as follows:

		Debt
		To Total		~~Fixed Charge~~
Borrower		Capitalization		~~Ratio~~
FirstEnergy	~~0.55~~		0.54 to 1.00	~~4.55~~
OE			0.39 to 1.00	~~6.66~~
Penn	~~0.35~~		0.32 to 1.00	~~16.97~~
CEI	~~0.58~~		0.57 to 1.00	~~3.82~~
TE			0.43 to 1.00	~~3.48~~
JCP&L	~~0.31~~		0.29 to 1.00	~~4.94~~
Met-Ed			0.38 to 1.00	~~7.01~~
Penelec	~~0.35~~		0.34 to 1.00	~~5.63~~

The facility does not contain any provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in ~~the~~ credit ratings. Pricing is defined in ~~"pricing grids"~~“pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the ~~second~~third quarter of 2005 was ~~2.93%~~3.50% for the regulated companies’ money pool and ~~2.86%~~3.46% for the unregulated companies' money pool.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The ~~total principal or par value~~following table displays FirstEnergy’s and its EUOC’s securities ratings as of ~~optional redemptions during~~October 3, 2005. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is Positive.

Ratings of Securities	Securities	S&P	Moody’s	Fitch

FirstEnergy	Senior unsecured	BBB-	Baa3	BBB-

OE	Senior unsecured	BBB-	Baa2	BBB
	Preferred stock	BB+	Ba1	BBB-

CEI	Senior secured	BBB	Baa2	BBB-
	Senior unsecured	BBB-	Baa3	BB

TE	Senior secured	BBB	Baa2	BBB-
	Preferred stock	BB+	Ba2	BB-

Penn	Senior secured	BBB+	Baa1	BBB+
	Senior unsecured ⁽¹⁾	BBB-	Baa2	BBB
	Preferred stock	BB+	Ba1	BBB-

JCP&L	Senior secured	BBB+	Baa1	BBB+
	Preferred stock	BB+	Ba1	BBB

Met-Ed	Senior secured	BBB+	Baa1	BBB+
	Senior unsecured	BBB	Baa2	BBB

Penelec	Senior unsecured	BBB	Baa2	BBB

Cash Flows From Investing Activities

Net cash flows used infor investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes the investment activities for the three months and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 by FirstEnergy’s regulated services, power supply management services and other segments:

Net cash used for investing activities was ~~$285~~$311 million in the ~~second~~third quarter of 2005 compared to ~~$61~~$43 million of cash provided from investing activities in the same period of 2004. The change was primarily due to ~~$193 million of lower proceeds from assets sales, a $36~~an $83 million increase in property additions and ~~an $83~~the absence in 2005 of $278 million ~~change~~ in ~~interest rate swap activity.~~cash proceeds from certificates of deposit (released collateral) received in the third quarter of 2004. Net cash used for investing activities increased by ~~$286~~$608 million in the first ~~six~~nine months of 2005 compared to the same period of 2004. The increase principally resulted from a $210 million increase in property additions, lower proceeds from the sale of assets of ~~$150 million, increased property additions of $127~~$152 million and ~~a $47 million change in interest rate swap activity, partially offset by~~ the absence in 2005 of ~~a $51~~$278 million ~~NUG trust refund~~of cash proceeds from certificates of deposit (released collateral) received in 2004.

~~During~~In the ~~second half~~last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately ~~$622 million, including $24 million for nuclear fuel.~~$378 million. FirstEnergy ~~has~~and the Companies have additional requirements of approximately ~~$41~~$312 million for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about ~~$3.3~~$3.5 billion (excluding nuclear fuel), of which ~~$1.0~~$1.1 billion applies to 2005. Investments for additional nuclear fuel during the 2005-2007 ~~period~~periods are estimated to be approximately ~~$282~~$285 million, of which approximately ~~$58~~$59 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately ~~$284~~$282 million and $86 million respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.

47

As of ~~June~~September 30, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled ~~$2.4~~$2.7 billion as summarized below:

Maximum

Guarantees and Other Assurances

Exposure

(In millions)

FirstEnergy guarantees of subsidiaries:
Energy and energy-related contracts ⁽¹⁾
$ 897
Other ⁽²⁾
172
1,069

Surety bonds 296
Letters of credit ⁽³⁾⁽⁴⁾
1,058

Total Guarantees and Other Assurances $ 2,423

⁽¹⁾Issued for a one-year term, with a 10-day termination right by FirstEnergy.

⁽²⁾Issued for various terms.

⁽³⁾Includes $140 million issued for various terms under LOC capacity available

under FirstEnergy's revolving credit agreement and $299 million outstanding in
support of pollution control revenue bonds issued with various maturities.
⁽⁴⁾Includes approximately $194 million pledged in connection with the sale and

leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection
with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged
in connection with the sale and leaseback of Perry Unit 1 by OE.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or ~~"material~~“material adverse ~~event"~~event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of ~~June~~September 30, 2005:

Total

Collateral Paid

Remaining

Collateral Provisions

Exposure

Cash

LOC

Exposure

(In millions)

Credit rating downgrade $ 367 $ 141 $ 18 $ 208
Adverse event 50 - 7 43
Total $ 417 $ 141 $ 25 $ 251

As a result of S&P's credit rating upgrade described above, $109 million of cash collateral was returned to FirstEnergy in October 2005.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided an LOC ($47 million as of ~~June~~September 30, 2005, which is included in the caption ~~"Other"~~“Other” in the above table of Guarantees and Other Assurances), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through ~~the~~ operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3 billion as of ~~June~~September 30, 2005.

FirstEnergy has equity ownership interests in certain ~~various~~ businesses that are accounted for ~~using~~under the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations, are disclosed under contractual obligations above.

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

FirstEnergy is exposed to ~~market~~price risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel, emission allowance prices and energy transmission. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair market value and be marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchases and normal sales exception under ~~the~~ SFAS 133 ~~exemption~~ and are therefore excluded from the table below. Of those contracts not exempt from such treatment, most are non-trading contracts that do not qualify for hedge accounting treatment. The change in the fair value of commodity derivative contracts related to energy production during the ~~second~~third quarter and first ~~six~~nine months of 2005 is summarized in the following table:

Derivatives are included on the Consolidated Balance Sheet as of ~~June~~September 30, 2005 as follows:

Balance Sheet Classification

Non-Hedge

Hedge

Total

(In millions)

Current -

Other assets $ 1 $ 2 $ 3
Other liabilities (1 ) (4 ) (5 )

Non-Current -

Other deferred charges 55 24 79
Other non-current liabilities - (12 ) (12 )

Net assets $ 55 $ 10 $ 65

The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

Sources of Information -

Fair Value by Contract Year

2005 ⁽¹⁾

2006

2007

2008

2009

Thereafter

Total

(In millions)

Prices actively quoted ⁽²⁾
$ 1 $ 1 $ - $ - $ - $ - $ 2
Other external sources ⁽³⁾
9 8 10 - - - 27
Prices based on models - - - 8 8 8 24
Total ⁽⁴⁾
$ 10 $ 9 $ 10 $ 8 $ 8 $ 8 $ 53

⁽¹⁾ For the last two quarters of 2005.

⁽²⁾ Exchange traded.

⁽³⁾ Broker quote sheets.

⁽⁴⁾ Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of ~~June~~September 30, 2005. Based on derivative contracts held as of ~~June~~September 30, 2005, an adverse 10% change in commodity prices would decrease net income by approximately $2$1 million for the next twelve months.

FirstEnergy utilizes fixed-to-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the ~~second~~third quarter of 2005, FirstEnergy executed no new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $350 million (see Note 7). As of ~~June~~September 30, 2005, the debt underlying the ~~$1.4~~$1.05 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of ~~5.54%~~5.66%, which the swaps have effectively converted to a current weighted average variable interest rate of ~~4.43%~~5.23%.

Forward Starting Swap Agreements - Cash Flow Hedges

During the third quarter, FirstEnergy entered into several forward starting swap agreements (forward swap) in order to hedge a portion of the consolidated interest rate risk associated with the planned issuance of fixed-rate, long-term debt securities for one or more of its consolidated entities in the fourth quarter of 2006. These derivatives are treated as cash flow hedges, protecting against the risk of changes in ~~the~~ future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of ~~June~~September 30, 2005, ~~FirstEnergy~~the forward swaps had ~~entered into forward starting swaps with an aggregate notional amount~~a fair value of ~~$375~~$2 million.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately ~~$976 million~~$1.038 billion and $951 million as of ~~June~~September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$98~~$104 million reduction in fair value as of ~~June~~September 30, 2005.

CREDIT RISK

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of ~~June~~September 30, 2005, the largest credit concentration was with one party, currently rated investment grade that represented 8% of FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and ~~reserve,~~reserves, were with investment-grade counterparties as of ~~June~~September 30, 2005.

Outlook

State Regulatory Matters

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:

·

restructuring the electric generation business and allowing the Companies' customers to select a

competitive electric generation supplier other than the Companies;

·

establishing or defining the PLR obligations to customers in the Companies' service areas;

5154

·

providing the Companies with the opportunity to recover potentially stranded investment (or transition costs)

not otherwise recoverable in a competitive generation market;

·

itemizing (unbundling) the price of electricity into its component elements - including generation,

transmission, distribution and stranded costs recovery charges;

·

continuing regulation of the Companies' transmission and distribution systems; and

·

requiring corporate separation of regulated and unregulated business activities.

The EUOCs recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

June 30,

December 31,

Increase

Regulatory Assets by Source

2005

2004

(Decrease)

(In millions)

Regulatory transition costs $ 4,380 $ 4,889 $ (509 )
Customer shopping incentives * 736 612 124
Customer receivables for future income taxes 296 246 50
Societal benefits charge 30 51 (21 )
Loss on reacquired debt 85 89 (4 )
Employee postretirement benefit costs 60 65 (5 )
Nuclear decommissioning, decontamination
and spent fuel disposal costs (166 ) (169 ) 3
Asset removal costs (361 ) (340 ) (21 )
Property losses and unrecovered plant costs 40 50 (10 )
MISO transmission costs 20 - 20
JCP&L reliability costs 27 - 27
Other 31 39 (8 )
Total $ 5,178 $ 5,532 $ (354 )

* The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in
   accordance with the transition and rate stabilization plans. These regulatory assets, totaling $736 million as of
   June 30, 2005 (OE - $274 million, CEI - $354 million, TE - $108 million) will be recovered through a surcharge
   equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new
   regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period
   will be equal to the surcharge revenue recognized during that period.

FirstEnergy is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. The FERC or other applicable government agencies and reliability coordinators, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy's filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted ~~a Memorandum of Understanding (MOU)~~an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The Energy Policy Act of 2005 provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and compliance responsibility for the new reliability standards. The FERC expects to adopt a final rule on or before February 2006 regarding certification requirements for the ERO and regional entities.

The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the final rule, the NERC will be required to make a filing with the FERC to obtain certification as the ERO. The proposed rule also provides for regional reliability organizations designed to replace the current regional councils. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to consolidate their regions into a new regional reliability organization known as ReliabilityFirst Corporation. Their intent is to file and obtain certification under the final rule as a “regional entity”. All of FirstEnergy’s facilities would be located within the ReliabilityFirst region.

On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

The impact of this effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the Energy Policy Act of 2005 requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

See Note 14 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio ~~Companies' Rate Stabilization Plan extends current~~Companies to establish generation ~~prices through 2008, ensuring adequate generation~~service rates beginning January 1, 2006, in response to PUCO concerns about price and supply ~~at stabilized prices, and continues~~uncertainty following the end of the Ohio Companies' ~~support of energy efficiency and economic~~transition plan market development ~~efforts. On~~period. In October ~~1 and October 4,~~ 2004, the OCC and NOAC ~~respectively,~~ filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order ~~and~~in this proceeding as well as the associated entries on rehearing. ~~Other key components of~~On September 28, 2005, the ~~Rate Stabilization Plan include~~Ohio Supreme Court heard oral argument on the ~~following:~~appeals.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a ~~generation rate adjustment~~GCAF rider under the ~~Rate Stabilization Plan.~~RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately ~~$93~~$88 million in 2006). Various parties including the OCC have intervened in this ~~case. The~~case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, the Ohio Companies ~~have received discovery requests from the OCC and~~filed an application with the PUCO ~~staff. A procedural schedule has been established by~~that, if approved, would supplement their existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with ~~a hearing scheduled~~the RCP proceedings and set hearings for ~~October 4,~~the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

On· Maintain the existing level of base distribution rates through December ~~9, 2004,~~31, 2008 for OE and TE, and

April 30, 2009 for CEI;

· Defer and capitalize certain distribution costs to be incurred during the ~~PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved Rate Stabilization Plan will take effect on~~period January 1, ~~2006. The~~2006

through December 31, 2008, not to exceed $150 million in each of the three years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized

costs will occur as of December 31, 2008 for OE and TE, and as of December 31, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE,

$45 million for TE, and $85 million for CEI by accelerating the application of each respective

company's accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and

2008, respectively, from all OE and TE distribution and transmission customers through a fuel

recovery mechanism and OE, TE, and CEI may defer and capitalize increased fuel costs above the

amount collected through the fuel recovery mechanism.

Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a ~~similar~~ competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in ~~2004.~~2004 which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the ~~Rate Stabilization Plan~~RSP pricing, ~~but not~~with no accounting impacts to the ~~related approved accounting,~~RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

~~New Jersey~~

The 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively. On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

53

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order (Phase I Order). The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

·~~An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;~~

·~~An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;~~

·An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

·~~An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and~~

·A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity to its previous level of 9.5% after the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% when the target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with the accelerated tree trimming costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On May 5, 2005, the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested that the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The auction is scheduled to take place in February 2006 for the supply period beginning June 1, 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

~~See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.~~

Pennsylvania

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

54

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices.On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

~~Transmission~~New Jersey

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (Phase I order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

· An annual increase in distribution revenues of $23 million, effective June 1, 2005, associated with the

Phase I Order reconsideration;

· An annual increase in distribution revenues of $36 million, effective June 1, 2005, related to JCP&L's

Phase II Petition;

· An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in

anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred

cost balance;

· An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

· A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in

JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two

consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the

target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September ~~16,~~30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began in the spring of 2005. CEI filed for rehearing of the orderestimated $528 million (in 2003 dollars) from the ~~FERC~~prior 1995 decommissioning study. The Ratepayer Advocate filed comments on ~~October~~February 28, 2005. On March 18, ~~2004. On April 15,~~ 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

See Note 14 to the ~~FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market, which became effective April 1, 2005. While the order on rehearing is favorable to CEI, the impact~~consolidated financial statements for further details and a complete discussion of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.regulatory matters in New Jersey.

Transmission

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted ~~thereafter~~ each July 1.1 thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. IfThe PUCO approved the settlement stipulation ~~is approved by the PUCO, the actual amounts~~on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $61.2 million. This value includes the ~~January 1,~~recovery of the 2005 deferred MISO expenses as described below. In May 2006, ~~rider~~the Ohio Companies will ~~be submitted~~file a modification to the ~~PUCO on or before November 1, 2005.~~rider which will determine revenues from July 2006 through June 2007.

The second application ~~seeks~~sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. ~~Deferral of all~~Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, ~~is pending.~~was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio ~~Companies~~Companies' and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The ~~Ohio Companies and the~~ OCC ~~have sixty days from that date to file~~filed a notice of appeal with the Ohio Supreme ~~Court.~~ Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On ~~June~~September 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

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Environmental Matters

The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably ~~determine~~estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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FirstEnergy plans to issue a report ~~that will disclose the Companies’ environmental activities, including their plans~~regarding its response to ~~respond to environmental~~air emission requirements. FirstEnergy expects to complete the report by December 1, ~~2005 and will post the report on its web site,~~ ~~www.firstenergycorp.com~~.2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~will require~~provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). in all cases from the 2003 levels. The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas ~~our~~their New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides for a cap-and-trade program to reduce mercury emissions ~~in two phases~~ from coal-fired power ~~plants.~~plants in two phases. Initially, mercury emissions will ~~decline~~be capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR ~~program.~~program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. ~~The~~However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities ~~covering~~alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the ~~U.S. Department of Justice (DOJ)~~DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, ~~that~~ was approved by the Court on July 11, 2005, requires OE and Penn to reduce ~~emissions from~~NOx and SO₂emission at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control ~~devices requiring capital~~devices. Capital expenditures necessary to meet those requirements are currently estimated to be ~~$1.1~~$1.5 billion ~~(primarily~~(the primary portion of which is expected to be spent in the 2008 to 2011 time period). As disclosed in FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy ~~purchase~~purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~June~~September 30, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. ~~Included in Current Liabilities and Other Noncurrent Liabilities are accrued~~Total liabilities ~~aggregating~~of approximately $64 million ~~as of June~~(JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $0.1 million and other - $14.6 million) have been accrued through September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The ~~most significant~~other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages ~~concluded,~~concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report ~~concludes,~~concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 ~~"recommendations~~“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of ~~June~~September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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~~Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking~~FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to ~~represent customers who allegedly suffered damages as a result of~~ the August 14, 2003 power ~~outages. All three~~outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. ~~Two of these~~In both such cases ~~were refiled at~~ the ~~PUCO, one in 2004 and another in 2005. In each,~~ individual ~~complainants��~~complainants—three in one case and four in the other—~~seek damages related to the outages and also seek~~sought to represent others as part of a class action. ~~FirstEnergy has filed responsive pleadings to both cases.~~ The PUCO ~~has~~ dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. ~~Both~~Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are ~~otherwise currently pending further proceedings.~~not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to ~~the two~~these six cases, ~~that were refiled at the PUCO,~~ the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. ~~FirstEnergy filed a~~FirstEnergy's motion to dismiss ~~with~~ the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on ~~October 22, 2004.~~or about December 1, 2005. No ~~timetable for a decision on the motion to dismiss has been established by the Court. No damage~~ estimate ~~has been provided and thus~~of potential liability has ~~not~~ been ~~determined.~~undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. ~~On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV.~~ FirstEnergy accrued $2.0 million for ~~the proposed~~a potential fine ~~in 2004~~prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

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On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant). On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under ~~the~~ heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial ~~condition.~~condition, results of operations and cash flows.

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On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

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NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP No. FAS 13-1, "Accounting for Rental Costs Incurred during the Construction Period"

Issued in October 2005, FSP No. FAS 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. The effective date of the FSP guidance is the first reporting period beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP, and its impact on the financial statements.

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. See Note 2 for an example of FirstEnergy's application of this Issue.

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with FirstEnergy's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for FirstEnergy in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

SFAS 154 - ~~"Accounting~~“Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in ~~an income statement.~~the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate ~~effected~~affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.

~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"~~

64

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

~~On March 30, 2005,~~In December 2004, the FASB issued ~~FIN 47 to clarify~~SFAS 153 amending APB 29, which was based on the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligationprinciple that ~~is conditional~~nonmonetary assets should be measured based on ~~a future event, if~~ the fair value of the ~~liability can be reasonably estimated. In instances where there is insufficient information~~assets exchanged. The guidance in APB 29 included certain exceptions to ~~estimate~~that principle. SFAS 153 eliminates the ~~liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the~~exception from fair value ~~cannot be reasonably estimated,~~measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that ~~fact and~~do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the ~~reasons why must be disclosed.~~future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This ~~Interpretation~~FSP is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy is currently evaluating the effect this Interpretation willnot expected to have a material impact on ~~its~~FirstEnergy's financial statements.

SFAS 123(R), ~~"Share-Based Payment"~~“Share-Based Payment”

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for ~~FirstEnergy and other~~ companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. ~~The Company will be applying~~FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. ~~Any potential~~Potential cumulative adjustments, if any, have not yet been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options for disclosure purposes only and ~~will continue~~expects to ~~do so~~apply this pricing model upon adoption of SFAS 123(R).

59

~~EITF Issue~~SFAS 151, “Inventory Costs - an amendment of ARB No. ~~03-1,~~43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In ~~March 2004,~~September 2005, the ~~EITF reached a consensus on the application guidance for Issue 03-1.~~FASB finalized and renamed EITF 03-1 ~~provides~~and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a ~~model for determining~~Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when ~~investments in certain debt and equity securities are considered~~the impairment is deemed other than ~~temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value~~temporary, even if a decision to sell has not been made, and ~~the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to~~(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after ~~June~~September 15, ~~2004, were delayed indefinitely by~~2005. The FASB expects to issue this FSP in the ~~issuance~~fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP ~~EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues to evaluate~~and any impact on its ~~investments as required by existing authoritative guidance.~~investments.

~~FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004"~~FSP 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) ~~"qualified~~“qualified production activities income,"” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). ~~This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer.~~ The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, ~~"Accounting~~“Accounting for Income ~~Taxes." FirstEnergy~~Taxes", which is ~~currently evaluating this FSP and does not expect it to have a material impact on the Company's financial statements.~~consistent with FirstEnergy's accounting.

60

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2005

2004

2005

2004

(In thousands)

STATEMENTS OF INCOME

OPERATING REVENUES
$ 716,612 $ 718,347 $ 1,442,970 $ 1,461,642

OPERATING EXPENSES AND TAXES:

Fuel 12,006 13,844 23,922 28,914
Purchased power 227,507 237,826 474,097 487,707
Nuclear operating costs 92,607 74,392 188,260 154,033
Other operating costs 95,589 91,797 178,768 177,157
Provision for depreciation 31,654 30,215 57,706 60,144
Amortization of regulatory assets 109,670 100,124 221,441 213,819
Deferral of new regulatory assets (39,026 ) (25,167 ) (63,821 ) (44,062 )
General taxes 46,043 39,488 94,121 88,054
Income taxes 91,192 65,787 146,164 127,361
Total operating expenses and taxes 667,242 628,306 1,320,658 1,293,127

OPERATING INCOME
49,370 90,041 122,312 168,515

OTHER INCOME (net of income taxes)
16,860 16,787 17,283 33,144

NET INTEREST CHARGES:

Interest on long-term debt 15,732 16,395 31,341 32,984
Allowance for borrowed funds used during construction
and capitalized interest (3,006 ) (1,593 ) (5,241 ) (2,974 )
Other interest expense 5,670 4,046 8,264 6,936
Subsidiary's preferred stock dividend requirements 738 640 1,378 1,280
Net interest charges 19,134 19,488 35,742 38,226

NET INCOME
47,096 87,340 103,853 163,433

PREFERRED STOCK DIVIDEND REQUIREMENTS
658 659 1,317 1,220

EARNINGS ON COMMON STOCK
$ 46,438 $ 86,681 $ 102,536 $ 162,213

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 47,096 $ 87,340 $ 103,853 $ 163,433

OTHER COMPREHENSIVE INCOME (LOSS):

Unrealized gain (loss) on available for sale securities (12,960 ) (1,021 ) (15,677 ) 4,146
Income tax (benefit) related to other comprehensive income (4,546 ) (421 ) (5,670 ) 1,709
Other comprehensive income (loss), net of tax (8,414 ) (600 ) (10,007 ) 2,437

TOTAL COMPREHENSIVE INCOME
$ 38,682 $ 86,740 $ 93,846 $ 165,870

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

6165

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	825,790		$	766,336		$	2,268,760		$	2,227,978

OPERATING EXPENSES AND TAXES:
Fuel		15,158			15,244			39,080			44,158
Purchased power		229,561			242,835			703,658			730,542
Nuclear operating costs		76,254			81,244			264,514			235,277
Other operating costs		114,762			99,132			293,530			276,289
Provision for depreciation		30,169			30,702			87,875			90,846
Amortization of regulatory assets		126,439			103,211			347,880			317,030
Deferral of new regulatory assets		(43,929	)		(25,728	)		(107,750	)		(69,790	)
General taxes		51,945			47,634			146,066			135,688
Income taxes		99,778			76,502			245,942			203,863
Total operating expenses and taxes		700,137			670,776			2,020,795			1,963,903

OPERATING INCOME		125,653			95,560			247,965			264,075

OTHER INCOME (net of income taxes)		20,069			17,141			37,352			50,285

NET INTEREST CHARGES:
Interest on long-term debt		12,989			10,657			44,330			43,641
Allowance for borrowed funds used during construction
and capitalized interest		(3,014	)		(1,950	)		(8,255	)		(4,924	)
Other interest expense		4,193			640			12,457			7,576
Subsidiary's preferred stock dividend requirements		156			639			1,534			1,919
Net interest charges		14,324			9,986			50,066			48,212

NET INCOME		131,398			102,715			235,251			266,148

PREFERRED STOCK DIVIDEND REQUIREMENTS		659			623			1,976			1,843

EARNINGS ON COMMON STOCK	$	130,739		$	102,092		$	233,275		$	264,305

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	131,398		$	102,715		$	235,251		$	266,148

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities		(3,402	)		(6,913	)		(19,079	)		(2,767	)
Income tax benefit related to other comprehensive income		2,043			2,850			7,713			1,141
Other comprehensive loss, net of tax		(1,359	)		(4,063	)		(11,366	)		(1,626	)

TOTAL COMPREHENSIVE INCOME	$	130,039		$	98,652		$	223,885		$	264,522

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2005

2004

(In thousands)

ASSETS

UTILITY PLANT:

In service $ 5,553,362 $ 5,440,374
Less - Accumulated provision for depreciation 2,770,924 2,716,851
2,782,438 2,723,523
Construction work in progress -
Electric plant 226,124 203,167
Nuclear fuel - 21,694
226,124 224,861
3,008,562 2,948,384
OTHER PROPERTY AND INVESTMENTS:

Investment in lease obligation bonds 341,582 354,707
Nuclear plant decommissioning trusts 447,649 436,134
Long-term notes receivable from associated companies 207,430 208,170
Other 45,394 48,579
1,042,055 1,047,590
CURRENT ASSETS:

Cash and cash equivalents 1,283 1,230
Receivables -
Customers (less accumulated provisions of $6,282,000 and $6,302,000, respectively,
for uncollectible accounts) 282,283 274,304
Associated companies 167,260 245,148
Other (less accumulated provisions of $52,000 and $64,000, respectively,
for uncollectible accounts) 10,549 18,385
Notes receivable from associated companies 598,151 538,871
Materials and supplies, at average cost 108,221 90,072
Prepayments and other 20,324 13,104
1,188,071 1,181,114
DEFERRED CHARGES:

Regulatory assets 935,223 1,115,627
Property taxes 61,419 61,419
Unamortized sale and leaseback costs 57,670 60,242
Other 67,867 68,275
1,122,179 1,305,563
$ 6,360,867 $ 6,482,651
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:

Common stockholder's equity -
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding $ 2,099,089 $ 2,098,729
Accumulated other comprehensive loss (57,125 ) (47,118 )
Retained earnings 367,734 442,198
Total common stockholder's equity 2,409,698 2,493,809
Preferred stock 60,965 60,965
Preferred stock of consolidated subsidiary 14,105 39,105
Long-term debt and other long-term obligations 1,104,584 1,114,914
3,589,352 3,708,793
CURRENT LIABILITIES:

Currently payable long-term debt 289,215 398,263
Short-term borrowings -
Associated companies 82,389 11,852
Other 143,912 167,007
Accounts payable -
Associated companies 100,452 187,921
Other 12,824 10,582
Accrued taxes 172,478 153,400
Other 84,545 74,663
885,815 1,003,688
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 724,040 766,276
Accumulated deferred investment tax credits 55,800 62,471
Asset retirement obligation 350,387 339,134
Retirement benefits 314,543 307,880
Other 440,930 294,409
1,885,700 1,770,170
COMMITMENTS AND CONTINGENCIES (Note 13)

$ 6,360,867 $ 6,482,651

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

6266

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2005

2004

2005

2004

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 47,096 $ 87,340 $ 103,853 $ 163,433
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation 31,654 30,215 57,706 60,144
Amortization of regulatory assets 109,670 100,124 221,441 213,819
Deferral of new regulatory assets (39,026 ) (25,167 ) (63,821 ) (44,062 )
Nuclear fuel and lease amortization 9,493 10,591 18,663 21,852
Amortization of lease costs (35,982 ) (35,482 ) (2,952 ) (2,452 )
Amortization of electric service obligation (3,991 ) - (3,991 ) -
Deferred income taxes and investment tax credits, net 19,485 (20,542 ) (5,142 ) (50,587 )
Accrued retirement benefit obligations 4,627 6,106 6,661 17,229
Accrued compensation, net 850 (372 ) (3,157 ) 4,032
Decrease (increase) in operating assets -
Receivables (8,378 ) 127,707 77,745 75,772
Materials and supplies (2,315 ) (3,104 ) (18,149 ) (5,866 )
Prepayments and other current assets 5,657 5,315 (7,220 ) (6,514 )
Increase (decrease) in operating liabilities -
Accounts payable (45,373 ) (334,764 ) (85,227 ) (93,785 )
Accrued taxes (25,370 ) (30,877 ) 19,078 (342,454 )
Accrued interest (7,784 ) (5,553 ) (791 ) (110 )
Prepayment for electric service - education programs 136,142 - 136,142 -
Other 6,357 (11,403 ) 18,071 (5,294 )
Net cash provided from (used for) operating activities 202,812 (99,866 ) 468,910 5,157

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing -
Long-term debt 146,450 - 146,450 30,000
Short-term borrowings, net 16,260 - 47,442 -
Redemptions and Repayments -
Preferred stock (37,750 ) - (37,750 ) -
Long-term debt (244,721 ) (19,809 ) (260,508 ) (116,810 )
Short-term borrowings, net - (94,155 ) - (77,814 )
Dividend Payments -
Common stock (130,000 ) (117,000 ) (177,000 ) (171,000 )
Preferred stock (658 ) (659 ) (1,317 ) (1,220 )
Net cash used for financing activities (250,419 ) (231,623 ) (282,683 ) (336,844 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (41,675 ) (47,302 ) (121,458 ) (84,963 )
Contributions to nuclear decommissioning trusts (7,885 ) (7,885 ) (15,770 ) (15,770 )
Loan repayments from (loans to) associated companies, net 95,498 359,878 (58,540 ) 408,790
Other 1,748 27,139 9,594 23,411
Net cash provided from (used for) investing activities 47,686 331,830 (186,174 ) 331,468

Net increase (decrease) in cash and cash equivalents 79 341 53 (219 )
Cash and cash equivalents at beginning of period 1,204 1,323 1,230 1,883
Cash and cash equivalents at end of period $ 1,283 $ 1,664 $ 1,283 $ 1,664

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	5,573,996		$	5,440,374
Less - Accumulated provision for depreciation		2,793,343			2,716,851
		2,780,653			2,723,523
Construction work in progress -
Electric plant		246,325			203,167
Nuclear fuel		17,972			21,694
		264,297			224,861
		3,044,950			2,948,384
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		341,335			354,707
Nuclear plant decommissioning trusts		462,439			436,134
Long-term notes receivable from associated companies		207,089			208,170
Other		44,623			48,579
		1,055,486			1,047,590
CURRENT ASSETS:
Cash and cash equivalents		900			1,230
Receivables -
Customers (less accumulated provisions of $7,312,000 and $6,302,000, respectively,
for uncollectible accounts)		285,462			274,304
Associated companies		121,262			245,148
Other (less accumulated provisions of $14,000 and $64,000, respectively,
for uncollectible accounts)		20,653			18,385
Notes receivable from associated companies		798,513			538,871
Materials and supplies, at average cost		92,610			90,072
Prepayments and other		17,336			13,104
		1,336,736			1,181,114
DEFERRED CHARGES:
Regulatory assets		844,590			1,115,627
Property taxes		61,419			61,419
Unamortized sale and leaseback costs		56,477			60,242
Other		67,093			68,275
		1,029,579			1,305,563
	$	6,466,751		$	6,482,651
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding	$	2,099,099		$	2,098,729
Accumulated other comprehensive loss		(58,484	)		(47,118	)
Retained earnings		434,473			442,198
Total common stockholder's equity		2,475,088			2,493,809
Preferred stock		60,965			60,965
Preferred stock of consolidated subsidiary		14,105			39,105
Long-term debt and other long-term obligations		1,099,147			1,114,914
		3,649,305			3,708,793
CURRENT LIABILITIES:
Currently payable long-term debt		273,656			398,263
Short-term borrowings -
Associated companies		120,971			11,852
Other		123,584			167,007
Accounts payable -
Associated companies		81,980			187,921
Other		11,289			10,582
Accrued taxes		213,843			153,400
Other		117,268			74,663
		942,591			1,003,688
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		688,702			766,276
Accumulated deferred investment tax credits		52,108			62,471
Asset retirement obligation		364,525			339,134
Retirement benefits		320,044			307,880
Other		449,476			294,409
		1,874,855			1,770,170
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,466,751		$	6,482,651

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

6367

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	131,398		$	102,715		$	235,251		$	266,148
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		30,169			30,702			87,875			90,846
Amortization of regulatory assets		126,439			103,211			347,880			317,030
Deferral of new regulatory assets		(43,929	)		(25,728	)		(107,750	)		(69,790	)
Nuclear fuel and lease amortization		11,867			11,914			30,530			33,766
Amortization of lease costs		32,963			33,037			30,011			30,585
Amortization of electric service obligation		(4,565	)		-			(8,556	)		-
Deferred income taxes and investment tax credits, net		(17,787	)		(11,374	)		(22,929	)		(61,961	)
Accrued retirement benefit obligations		5,503			7,253			12,164			24,482
Accrued compensation, net		1,254			1,106			(1,903	)		5,138
Pension trust contribution		-			(72,763	)		-			(72,763	)
Decrease (increase) in operating assets -
Receivables		32,715			(86,506	)		110,460			(10,734	)
Materials and supplies		15,611			(2,930	)		(2,538	)		(8,796	)
Prepayments and other current assets		2,988			4,878			(4,232	)		(1,636	)
Increase (decrease) in operating liabilities -
Accounts payable		(20,007	)		115,690			(105,234	)		21,905
Accrued taxes		41,365			(4,464	)		60,443			(346,918	)
Accrued interest		2,458			3,028			1,667			2,918
Prepayment for electric service - education programs		-			-			136,142			-
Other		(11,504	)		2,572			1,372			(8,624	)
Net cash provided from operating activities		336,938			212,341			800,653			211,596

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		-			-			146,450			30,000
Short-term borrowings, net		18,254			91,072			65,696			13,258
Redemptions and Repayments -
Preferred stock		-			-			(37,750	)		-
Long-term debt		(17,819	)		(36,090	)		(278,327	)		(152,900	)
Dividend Payments -
Common stock		(64,000	)		(68,000	)		(241,000	)		(239,000	)
Preferred stock		(659	)		(623	)		(1,976	)		(1,843	)
Net cash used for financing activities		(64,224	)		(13,641	)		(346,907	)		(350,485	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(69,346	)		(61,682	)		(190,804	)		(146,645	)
Contributions to nuclear decommissioning trusts		(7,885	)		(7,885	)		(23,655	)		(23,655	)
Loan repayments from (loans to) associated companies, net		(200,021	)		(378,081	)		(258,561	)		30,709
Proceeds from certificates of deposit		-			277,763			-			277,763
Other		4,155			(29,200	)		18,944			113
Net cash provided from (used for) investing activities		(273,097	)		(199,085	)		(454,076	)		138,285

Net decrease in cash and cash equivalents		(383	)		(385	)		(330	)		(604	)
Cash and cash equivalents at beginning of period		1,283			1,664			1,230			1,883
Cash and cash equivalents at end of period	$	900		$	1,279		$	900		$	1,279

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

68

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of ~~June~~September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~July 29,~~November 1, 2005

6469

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the ~~second~~third quarter of 2005 ~~decreased~~increased to ~~$46~~$131 million from ~~$87~~$102 million in the ~~second~~third quarter of 2004. The ~~decrease~~increase in earnings resulted primarily ~~resulted~~ from ~~increases in~~higher operating revenues and lower purchased power and nuclear operating costs, partially offset by increases in regulatory asset amortization, ~~general taxes and a one-time income tax charge, which were partially offset by lower purchased power~~other operating costs and ~~higher regulatory asset deferrals.~~income taxes. During the first ~~six~~nine months of 2005, earnings on common stock decreased to ~~$103~~$233 million from ~~$162~~$264 million in the same period of 2004. The decrease in earnings for the first ~~half~~nine months of 2005 primarily resulted from ~~reduced operating revenues and other income, and increased~~increases in nuclear operating costs, regulatory asset amortization and ~~the~~a one-time income tax ~~charge.~~charge that occurred in the second quarter of 2005, as well as a decrease in other income. These reductions to earnings were partially offset by ~~decreased~~higher operating revenues and lower fuel and purchased power ~~costs, as well as, increased regulatory asset deferrals.~~costs.

Operating revenues ~~decreased~~increased by $2$59 million or ~~0.2%~~7.8% in the ~~second~~third quarter of 2005 compared with the same period in 2004. ~~Lower~~Higher revenues for the quarter primarily resulted from ~~a $12 million decrease in wholesale sales, partially offset by increases in~~increased retail generation and distribution revenues of $6$23 million and $5$33 million, respectively. During the first ~~six~~nine months of 2005 compared to the same period in 2004, operating revenues ~~decreased~~increased by ~~$19~~$41 million or ~~1.3%~~1.8%. ~~Lower~~Higher revenues for the first ~~half~~nine months of 2005 were due to ~~a $36 million decrease in wholesale sales, partially offset by~~ increases in retail generation and distribution revenues of ~~$12~~$36 million and $7$40 million, ~~respectively.~~respectively, partially offset by a $37 million decrease in wholesale sales.

Lower wholesale revenues for the ~~second quarter and the~~ first ~~six~~nine months of 2005 reflected decreased sales to FES of ~~$22~~$57 million ~~(15.7%~~(12.1% KWH sales decrease) ~~and $50 million (18.1% KWH sales decrease)~~, ~~respectively,~~ due to reduced nuclear generation available for sale. The ~~decreases in~~decreased sales to FES were partially offset by increased sales of ~~$10~~$21 million ~~and $14 million, respectively,~~ to non-affiliated customers (including MSG sales). Under its Ohio transition plan, OE is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).

Increased retail generation revenues for the ~~second~~third quarter of 2005 resulted from ~~increased~~higher sales to residential, commercial and ~~commercial~~industrial customers of $7$10 million, $2 million and $1$11 million, ~~respectively, partially offset by a $2 million decrease in sales to industrial customers.~~respectively. The increased generation KWH sales to residential ~~(12.2%~~(14.0%) and commercial ~~(2.4%~~(6.1%) customers were due to warmer than normal temperatures in the ~~second~~third quarter of ~~2005 which increased air-conditioning loads. Lower~~2005. Increased industrial revenues reflected a ~~6.7% decrease~~6.5% increase in generation KWH ~~sales, partially offset by higher composite unit prices. The industrial~~sales. Partially offsetting the increase in residential KWH sales ~~decrease resulted from increased~~was an increase in customer shopping. Generation services provided to ~~industrial~~residential customers by alternative suppliers as a percent of total ~~industrial~~residential sales delivered in OE’s service area increased by ~~2.6~~1.2 percentage points compared with the ~~second~~third quarter of 2004. ~~Residential~~Commercial and ~~commercial~~industrial customer shopping remained relatively unchanged.

Retail generation revenues increased for the first ~~six~~nine months of 2005 compared to the same period of 2004 in all customer sectors (residential - $5$15 million, commercial - $4$7 million and industrial - $3$14 million). The higher ~~residential and commercial~~ revenues were due to increased generation KWH sales (residential - ~~3.3% and~~6.8%, commercial - ~~3.2%~~4.2% and industrial - 1.0%). ~~The increase in~~Residential and industrial ~~revenues reflected higher composite unit prices ($5 million),~~KWH sales increases were partially offset by ~~a 1.6% decrease~~increases in ~~generation KWH sales. Similar to the second quarter of 2005, industrial KWH sales decreased principally due to increased~~ customer shopping ~~(2.4~~by 1.1 and 1.7 percentage points, ~~increase compared with the 2004 period),~~respectively, while ~~residential and~~ commercial ~~customer~~ shopping remained relatively unchanged.

Revenues from distribution throughput increased $5$33 million in the ~~second~~third quarter of 2005 compared with the same period in 2004. Distribution deliveries to residential, commercial and industrial customers increased ~~$14~~by $26 million, $4 million and $3 million, respectively, due to ~~an 11.4% increase in~~increased KWH deliveries. The increases from distribution deliveries were partially offset by lower composite unit ~~prices. Distribution revenues from commercial and industrial customers decreased by $3 million and $7 million, respectively, primarily due to lower composite unit prices. Lower unit~~ prices in the commercial sector that reduced revenues by $5 million were partially offset by a 2.4% increase in KWH deliveries; industrial revenues decreased due to lower units prices ($4 million) and a 3.4% decrease in KWH deliveries. Residential and commercial KWH deliveries reflected warmer than normal temperatures in the second quarter of 2005.all sectors.

65

Revenues from distribution throughput increased $7$40 million in the first ~~six~~nine months of 2005 compared with the same period in 2004 due to higher revenues from residential and commercial customers, partially offset by lower ~~commercial and~~ industrial sector revenues. Residential and commercial distribution revenues increased ~~$13~~$40 million and $3 million, respectively, reflecting ~~a 4.4% increase in~~higher KWH ~~deliveries. Commercial~~deliveries partially offset by lower composite prices. Industrial distribution revenues ~~declined slightly with~~decreased by $3 million due to lower composite unit prices, partially offset by ~~a 3.0% increase in KWH deliveries. Industrial distribution revenues decreased by $6 million reflecting lower composite unit prices, partially offset by a 1.6%~~an increase in KWH distribution deliveries.

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Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $1$3 million from additional credits in the ~~second~~third quarter and $4$7 million in the first ~~six~~nine months of 2005 compared to the same periods in 2004. These revenue reductions are deferred for future recovery from customers under OE’s transition plan and do not affect current period earnings (See Regulatory Matters below).

Changes in ~~electric generation~~KWH sales ~~and distribution deliveries~~by customer class in the ~~second quarter~~three months and ~~first six~~nine months ofended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		9.1	%	3.9	%
Wholesale		(1.2	)%	(9.4	)%
Total Electric Generation Sales		4.0	%	(2.6	)%

Distribution Deliveries:
Residential		15.9	%	8.3	%
Commercial		6.3	%	4.2	%
Industrial		6.9	%	3.4	%
Total Distribution Deliveries		9.8	%	5.3	%

Changes in KWH Sales

Three Months

Six Months

Increase (Decrease)

Electric Generation:
Retail 1.6 % 1.4 %
Wholesale (9.8 )% (13.6 )%
Total Electric Generation Sales

(4.0
)%

(5.8
)%

Distribution Deliveries:
Residential 11.4 % 4.4 %
Commercial 2.4 % 3.0 %
Industrial (3.4 )% 1.6 %
Total Distribution Deliveries

2.8
%

3.0
%

Operating Expenses and Taxes

Total operating expenses and taxes increased by ~~$39~~$29 million in the ~~second~~third quarter and ~~$28~~$57 million in the first ~~six~~nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	Three Months			Nine Months
Increase (Decrease)	*(In millions)*
Fuel costs	$	--		$	(5	)
Purchased power costs		(13	)		(27	)
Nuclear operating costs		(5	)		29
Other operating costs		16			17
Provision for depreciation		(1	)		(3	)
Amortization of regulatory assets		23			31
Deferral of new regulatory assets		(18	)		(38	)
General taxes		4			11
Income taxes		23			42
Net increase in operating expenses and taxes	$	29		$	57

Operating Expenses and Taxes - Changes

Three Months

Six Months
Increase (Decrease)

(In millions)
Fuel costs $ (2 ) $ (5 )
Purchased power costs (10 ) (14 )
Nuclear operating costs 18 34
Other operating costs 4 2
Provision for depreciation 1 (2 )
Amortization of regulatory assets 10 8
Deferral of new regulatory assets (14 ) (20 )
General taxes 7 6
Income taxes 25 19
Net increase in operating expenses and taxes
$ 39 $ 28

Lower fuel costs in the ~~second quarter and~~ first ~~six~~nine months of 2005, compared with the same periods of 2004, resulted from decreased nuclear generation - down ~~15.7% and 18.1%, respectively.~~12.1%. Purchased power costs were lower in both periods of 2005, reflecting lower unit costs ~~and a reduction in~~partially offset by higher KWH ~~purchased~~purchases in the ~~first half~~third quarter of 2005. KWH purchases were relatively unchanged in the ~~second quarter.~~first nine months of 2005. Nuclear operating costs decreased in the third quarter of 2005 compared to the same quarter in 2004 primarily due to a decrease in non-fuel nuclear operating costs at Perry Unit 1 and Beaver Valley Unit 2. Nuclear operating costs increased during the first nine months of 2005 primarily due to the costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 that was completed on May 6, 2005. There were no nuclear refueling outages in the same periods last year. The ~~increase~~increases in other operating costs in the ~~second~~third quarter and first ~~six~~nine months of 2005, compared to the same periods of 2004, resulted primarily from ~~higher vegetation management costs and~~ increased MISO transmission expenses, partially offset by lower employee benefits expenses.

~~Depreciation in the second quarter of 2005 was relatively unchanged compared to the second quarter of 2004.~~ The decrease in depreciation expense in the first ~~six~~nine months of 2005 compared with the same period of 2004 was attributable to revised estimated service life assumptions for fossil generating ~~plants.~~plants (see Note 3). Higher regulatory asset amortization in ~~both~~the three-month and nine-month periods was primarily due to increased amortization of transition costs being recovered under the ~~Rate Stabilization Plan. Deferral of new~~RSP. Increases in regulatory ~~assets decreased expenses by $13 million in~~asset deferrals for both ~~the second quarter and the first six months of 2005 primarily~~periods resulted from ~~the PUCO-approved MISO~~higher shopping incentive deferrals and related interest ~~beginning in~~($4 million and $11 million, respectively), and the ~~second quarter of 2005 (see~~PUCO-approved MISO administrative cost deferrals and related interest ($14 million and $27 million, respectively, see Outlook - Regulatory Matters).

6671

General taxes increased in the ~~second~~third quarter and first ~~six~~nine months of 2005 compared to the same periods of 2004 ~~primarily~~ due to the effect of higher KWH sales which increased Ohio KWH excise taxes in both periods. The increase in the first nine months of 2005 also reflected the absence of a $6 million Pennsylvania property tax refund ~~recorded~~recognized in the second quarter of 2004.

Income taxes increased in the ~~second quarter and~~ first ~~six~~nine months of 2005 compared to the same periods of 2004, primarily due to the effects of new tax legislation in ~~Ohio (see Note 12 to consolidated financial statements).~~Ohio. On June 30, 2005, the State of Ohio enacted new tax legislation that ~~creates~~created a new ~~Commercial Activity Tax (CAT),~~CAT tax, which is based on qualifying ~~"taxable~~“taxable gross ~~receipts"~~receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax iswas effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually, beginning with the year ended 2005. During the phase-out period the Ohio income tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period.

As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. ~~Accordingly, OE’s~~The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was an additional tax expense ~~increased by~~of approximately $36 million, ~~for the three and six-month periods ended June 30, 2005. Income tax expense~~which was ~~reduced during the three and six-month periods ended June 30, 2005 by approximately $5 million~~partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income ~~tax.~~taxes by approximately $7 million in the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

Other Income

Other income decreased ~~$16~~$13 million in the first ~~six~~nine months of 2005 compared with the same period of 2004, primarily due to an $8.5 million civil penalty payable to the Department of Justice and a $10 million liability for environmental projects recognized in connection with the W.H. Sammis Plant settlement (see Outlook - Environmental Matters)., partially offset by higher nuclear decommissioning trust realized gains.

Net Interest Charges

Net interest charges ~~continued to trend lower, decreasing~~increased by ~~$0.4~~$4 million in the ~~second~~third quarter and $2 million in the first ~~six~~nine months of 2005 compared with the same periods of 2004, reflecting ~~$200 million~~increased short-term borrowings from associated companies at a higher rate of ~~debt redemptions since July 1, 2004.~~interest.

Capital Resources and Liquidity

OE’s cash requirements infor the remainder of 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debt and preferred stock outstanding. ~~Available borrowing~~Borrowing capacity under credit facilities ~~will be used~~is available to manage working capital requirements. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of ~~June~~September 30, 2005, OE's cash and cash equivalents of approximately $1 million remained unchanged from ~~its~~ December 31, ~~2004 balance.~~2004.

6772

Cash Flows From Operating Activities

Cash provided from operating activities during the ~~second~~third quarter and first ~~six~~nine months of 2005, compared with the corresponding periods in 2004 were as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	*(In millions)*

Cash earnings ⁽¹⁾	$	273	$	224		$	603	$	607
Pension trust contribution ⁽²⁾		--		(44	)		--		(44	)
Working capital and other		64		32			198		(351	)
Total cash flows from operating activities	$	337	$	212		$	801	$	212

⁽¹⁾ Cash earnings is a non-GAAP measure (see reconciliation below).
⁽²⁾ Pension trust contribution net of $29 million of income tax benefits.

Three Months Ended

Six Months Ended

June 30,

June 30,

Operating Cash Flows

2005

2004

2005

2004

(In millions)

Cash earnings ^(*)
$ 144 $ 153 $ 329 $ 383
Working capital and other 59 (253 ) 140 (378 )
Total cash flows form operating activities $ 203 $ (100 ) $ 469 $ 5

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. OE believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended				Six Months Ended				Three Months Ended						Nine Months Ended
	June 30,				June 30,				September 30,						September 30,
Reconciliation of Cash Earnings	2005		2004		2005		2004		2005			2004			2005			2004
	*(In millions)*								*(In millions)*

Net income (GAAP)	$	47	$	87	$	104	$	163	$	131		$	103		$	235		$	266
Non-cash charges (credits):
Provision for depreciation		32		30		58		60		30			31			88			91
Amortization of regulatory assets		110		100		221		214		126			103			348			317
Amortization of lease costs		(36)		(35)		(3)		(2)		33			33			30			31
Nuclear fuel and capital lease amortization		9		11		19		22		12			12			31			34
Deferral of new regulatory assets		(39)		(25)		(64)		(44)		(44	)		(26	)		(108	)		(70	)
Deferred income taxes and investment tax credits, net		19		(21)		(5)		(51)		(18	)		(40	)		(23	)		(91	)
Other non-cash items		2		6		(1)		21		3			8			2			29
Cash earnings (Non-GAAP)	$	144	$	153	$	329	$	383	$	273		$	224		$	603		$	607

Net cash provided from operating activities increased ~~$303~~$125 million in the ~~second~~third quarter of 2005, compared with the ~~second~~third quarter of 2004, due to a ~~$312~~$32 million increase from changes in working capital, ~~partially offset by~~the absence of a $9$44 million ~~decrease~~after-tax voluntary pension trust contribution made in the third quarter of 2004 and a $49 million increase in cash earnings as described above and under ~~"Results~~“Results from Operations". The increase in working capital primarily reflects net changes in accounts payable and accounts receivable to associated companies of $152 million and $136 million of funds received for prepaid electric service under the Energy for Education program.

Net cash from operating activities increased $464 million in the first six months of 2005, compared with the same period in 2004, due to a $518 million increase from changes in working capital, partially offset by a $54 million decrease in cash earnings as described above and under "Results from Operations"Operations”. The increase in working capital primarily reflects changes in accrued taxes of ~~$362~~$46 million ~~and $136 million of funds received for the Energy for Education program. The accrued taxes change includes~~(including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing ~~agreement~~agreement), partially offset by changes in accounts payable and accounts receivable of $16 million.

Net cash provided from operating activities increased $589 million in the first nine months of 2005, compared with the same period in 2004, due to a $549 million increase from changes in working capital, the absence of a $44 million after-tax voluntary pension trust contribution made in the third quarter of ~~2004.~~2004, partially offset by a $4 million decrease in cash earnings as described above and under “Results from Operations”. The increase in working capital primarily reflects changes in accrued taxes of $407 million (including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement) and $136 million of funds received for the Energy for Education program in the second quarter of 2005.

Cash Flows From Financing Activities

Net cash used for financing activities increased to ~~$250~~$64 million in the ~~second~~third quarter of 2005 from ~~$232~~$14 million in the ~~second~~third quarter of 2004. The increase primarily resulted from a ~~$13~~$72 million ~~increase~~decrease in ~~common stock dividends to FirstEnergy~~new short-term borrowings, partially offset by an $18 million decrease in redemptions and ~~a $6 million increase in net debt and preferred stock redemptions.~~repayments. Net cash used for financing activities decreased to ~~$283~~$347 million in the first ~~six~~nine months of 2005 from ~~$337~~$350 million in the same period of 2004. The decrease was due to a ~~$60~~$169 million ~~decrease~~increase in new debt and short term borrowings partially offset by a $163 million increase in net debt and preferred stock ~~redemptions, partially offset by a $6 million increase in common stock dividends to FirstEnergy.~~redemptions.

73

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, including accrued dividends to the date of redemption.

68

OE had approximately ~~$599~~$799 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and ~~$226~~$245 million of short-term indebtedness as of ~~June~~September 30, 2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has authorization from the SEC to incur short-term debt up to its charter limit of ~~$49~~$51 million (including the utility money pool). ~~In addition,~~

OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE. As of September 30, 2005, the facility was drawn for $120 million.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of ~~June~~September 30, 2005, the facility was ~~drawn for $20 million.~~not drawn. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

On April 6, 2004, Ohio Air Quality Development Authority and Ohio Water Development Authority pollution control bonds aggregating $100 million and $6.45 million, respectively, were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.

~~On July 1,~~As of October 24, 2005, Ohio Water Development Authority pollution control bonds aggregating $40 million were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance. OE provided FMB collateral to the bond insurer.

OE and Penn had the aggregate capability to issue approximately ~~$1.8~~$1.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage ~~indentures.~~indentures following the recently completed intra-system transfer of fossil generating plants (see Note 17). The issuance of FMB by OE is also subject to provisions of its senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE to incur additional secured debt not otherwise permitted by a specified exception of up to ~~$668~~$690 million as of ~~June 30,~~October 24, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of ~~$2.5~~$2.8 billion of preferred stock (assuming no additional debt was issued) as of ~~June~~September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the aggregate capability of OE and Penn to issue preferred stock by approximately 17%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and ~~will~~ mature on the earlier of 364 days from the date of borrowing ~~and~~or the commitment termination date, as the same may be extended. OE's and Penn’s borrowing limits under the facility are $550 million. The facility replaced FirstEnergy’s $375 million and $1 billion three-year credit agreements and OE’s $125 million three-year credit agreement, as well as OE’s recently-expired $250 million two-year credit agreement.

OE and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the ~~second~~third quarter of 2005 was ~~2.93%~~3.50%.

OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. ~~The ratings outlook from the rating agencies on all such securities is positive.~~

On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as its nuclear operations further stabilize.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s ~~rating~~ outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in ~~its~~their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash ~~flow.~~flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

74

Cash Flows From Investing Activities

Net cash provided from investing activities totaled $48 million in the second quarter of 2005 compared with $332 million for the same period in 2004. The $284 million change for the second quarter resulted primarily from a $264 million decrease in loan repayments from associated companies and a decrease in property additions. During the first six months of 2005, net cash used for investing activities ~~totaled $186 million compared to net cash provided from investing activities of $331~~increased by $74 million in the third quarter of 2005 and $592 million in the first nine months of 2005, from the same ~~period~~periods of 2004. ~~The $518 million change~~These increases resulted primarily from ~~a $467~~$278 million ~~position change~~in cash proceeds from ~~receiving loan repayments from associated companies in 2004 to issuing loans~~certificates of deposit during the third quarter 2004. Loans to associated companies decreased $178 million in the third quarter of 2005, partially offsetting the proceeds from certificates of deposit, and ~~a $36~~increased $289 million ~~increase~~ in ~~property additions.~~the first nine months of 2005.

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~~During~~In the ~~second half~~last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately ~~$133 million, including $17 million for nuclear fuel.~~$82 million. OE has additional requirements of approximately ~~$24~~$8 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn’s optional redemptions disclosed above) during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

OE’s capital spending for the period 2005-2007 is expected to be about $667 million ~~(excluding nuclear fuel),~~ of which approximately ~~$218~~$233 million applies to 2005. ~~Investments for additional~~

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear ~~fuel during~~and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include OE’s leasehold interests in certain of the ~~2005-2007 period~~plants that are ~~estimated~~currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the OE Companies completed the transfer of non-nuclear generation assets to FGCO. The OE Companies currently expect to complete the transfer of nuclear generation assets to NGC through a spin-off by way of dividend before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be ~~approximately $147 million,~~separated from the regulated delivery business of ~~which about $35 million applies~~those companies through transfer to ~~2005. During~~a separate corporate entity. FENOC currently operates and maintains the ~~same period, its~~ nuclear ~~fuel investments are expected~~generation assets to be ~~reduced~~transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by ~~approximately $129 million~~the restructuring plans by transferring the ownership interests to NGC and ~~$40 million,~~FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for OE's and Penn’s disclosure of the assets held for sale as ~~the nuclear fuel is consumed.~~of September 30, 2005.

Off-Balance Sheet Arrangements

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The present value of these operating lease commitments, net of trust investments, was ~~$663~~$678 million as of ~~June~~September 30, 2005.

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$251~~$262 million and $248 million as of ~~June~~September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$25~~$26 million reduction in fair value as of ~~June~~September 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.

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Outlook

The electric industry continues to transition to a more competitive environment and all of the OE Companies’ customers can select alternative energy suppliers. The OE Companies continue to deliver power to residential homes and businesses through their existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. ~~Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.~~

~~FirstEnergy Intra-System Generation Asset Transfers~~

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.

These transactions are being undertaken in connection with the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

As contemplated by the Agreements, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies and Penn at the values approved in the Ohio Transition Case.

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Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised ~~Rate Stabilization Plan.~~ RSP.

As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE's franchise area.

~~OE's Rate Stabilization Plan extends current~~On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation ~~prices through 2008, ensuring adequate generation~~service rates beginning January 1, 2006, in response to PUCO concerns about price and supply ~~at stabilized prices, and continues OE's support~~uncertainty following the end of ~~energy efficiency and economic~~the Ohio Companies' transition plan market development ~~efforts. On~~period. In October ~~1 and October 4,~~ 2004, the OCC and NOAC ~~respectively,~~ filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order ~~and~~in this proceeding as well as the associated entries on rehearing. ~~Other key components of~~On September 28, 2005, the ~~Rate Stabilization Plan include~~Ohio Supreme Court heard oral argument on the ~~following:~~appeals.

·

~~Amortization period for transition costs being recovered through the RTC for OE extends to as late as 2007;~~

·

~~Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and~~

·

~~Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.~~

On May 27, 2005, OE filed an application with the PUCO to establish a ~~generation rate adjustment~~GCAF rider under the ~~Rate Stabilization Plan.~~RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to OE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the ~~baseline.~~baseline (approximately $88 million in 2006 for all of the Ohio Companies). Various parties including the OCC have intervened in this ~~case. OE has received discovery requests from the OCC~~case and the ~~PUCO staff. A procedural schedule~~case has been ~~established by~~consolidated with the ~~PUCO, with a hearing scheduled for October 4, 2005.~~RCP application discussed below.

On ~~December~~September 9, ~~2004,~~2005, OE filed an application with the PUCO ~~rejected~~that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the ~~auction price results from a required competitive bid process~~PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and ~~issued an entry stating that~~set hearings for the ~~pricing~~consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the ~~approved Rate Stabilization Plan will take effect on~~RSP during the plan period, and to provide OE with financial results generally comparable to those attained under the RSP. Major provisions of the RCP include:

· Maintain the existing level of base distribution rates through December 31, 2008 for OE;

· Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during

the period January 1, ~~2006. The~~2006 through December 31, 2008, not to exceed $150 million in each of the

three years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of

authorized costs will occur as of December 31, 2008 for OE;

· Reduce the deferred shopping incentive balance as of January 1, 2006 by up to $75 million for OE

by accelerating the application of its accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and

2008, respectively, from all OE and TE distribution and transmission customers through a fuel

recovery mechanism. OE may defer and capitalize increased fuel costs above the amount

collected through the fuel recovery mechanism.

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Under provisions of the RSP, the PUCO may require OE to undertake, no more often than annually, a ~~similar~~ competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for OE in ~~2004.~~2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the ~~Rate Stabilization Plan~~RSP pricing, ~~but not~~with no accounting impacts to the ~~related approved accounting,~~RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $14 million per year; however, OE anticipates that this amount will increase. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted ~~thereafter~~ each July 1.1 thereafter. OE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by OE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. IfThe PUCO approved the settlement stipulation ~~is approved by the PUCO, the actual amounts~~on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $30.6 million. This value includes the ~~January 1,~~recovery of the 2005 deferred MISO expenses as described below. In May 2006, ~~rider~~OE will ~~be submitted~~file a modification to the ~~PUCO on or before November 1, 2005.~~rider which will determine revenues from July 2006 through June 2007.

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The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in ~~the~~ MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. ~~Deferral of all~~Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, ~~is pending.~~was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and OE each filed applications for rehearing. OE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied OE's and OCC’s applications and, at the request of OE, struck as untimely OPAE’s application. ~~OE and the~~The OCC ~~have sixty days from that date to file~~filed a notice of appeal with the Ohio Supreme ~~Court.~~ Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies’ brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

OE and Penn record as regulatory assets costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. OE’s regulatory assets as of ~~June~~September 30, 2005 and December 31, 2004, were ~~$0.9~~$0.8 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total ~~$274~~$302 million as of ~~June~~September 30, 2005 and, under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. ~~Recovery of~~See Note 14 “Regulatory Matters - Ohio” for the ~~new regulatory assets will begin at that time and~~estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the ~~regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.~~proposed RCP and current RSP. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately ~~$37~~$48 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of ~~June~~September 30, 2005 and December 31, 2004, respectively.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a ~~more~~ detailed discussion of reliability initiatives, including actions by the PPUC, that impact Penn.

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Environmental Matters

OE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably ~~determine~~estimate the amount of such costs. Unasserted claims are reflected in OE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report ~~that will disclose the Companies’ environmental activities, including their plans~~regarding its response to ~~respond to environmental~~air emission requirements. FirstEnergy expects to complete the report by December 1, ~~2005 and will post the report on its web site,~~ ~~www.firstenergycorp.com~~.2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~will require~~provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). in all cases from the 2003 levels. The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_x emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the OE Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions ~~in two phases~~ from coal-fired power ~~plants.~~plants in two phases. Initially, mercury emissions will ~~decline~~be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. ~~The future~~However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

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W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities ~~covering~~alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the ~~U.S. Department of Justice (DOJ)~~DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, ~~that~~ was approved by the Court on July 11, 2005, requires OE and Penn to reduce NO_x and SO₂emissions ~~from~~at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control ~~devices requiring capital~~devices. Capital expenditures necessary to meet those requirements are currently estimated to be ~~$1.1~~$1.5 billion ~~(primarily~~(the primary portion of which is expected to be spent in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy ~~purchase~~purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made ~~greenhouse gases~~GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic ~~greenhouse gas~~GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The OE Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by the OE Companies is lower than many regional competitors due to the OE Companies' diversified generation sources which include low or non-CO₂emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE's normal business operations pending against OE and its subsidiaries. The ~~most significant~~other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages ~~concluded,~~concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report ~~concludes,~~concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 ~~"recommendations~~“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of ~~June~~September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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~~Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking~~FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to ~~represent customers who allegedly suffered damages as a result of~~ the August 14, 2003 power ~~outages. All three~~outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. ~~Two of these~~In both such cases ~~were refiled at~~ the ~~PUCO, one in 2004 and another in 2005. In each,~~ individual complainants—three in one case and four in the other—~~seek damages related to the outages and also seek~~sought to represent others as part of a class action. ~~FirstEnergy has filed responsive pleadings to both cases.~~ The PUCO ~~has~~ dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. ~~Both~~Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are ~~otherwise currently pending further proceedings.~~not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to ~~the two~~these six cases, ~~that were refiled at the PUCO,~~ the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. ~~FirstEnergy filed a~~FirstEnergy's motion to dismiss ~~with~~ the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on ~~October 22, 2004.~~or about December 1, 2005. No ~~timetable for a decision on the motion to dismiss has been established by the Court. No damage~~ estimate ~~has been provided and thus~~of potential liability has ~~not~~ been ~~determined.~~undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two ~~years.~~years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which the OE Companies have a 35.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which ~~will~~ include owned portions of the plant).

On April 4, 2005, the NRC held a public ~~forum~~meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" ~~and met all cornerstone objectives although~~even though it remained under ~~the~~ heightened NRC ~~oversight since August 2004.~~oversight. During the public ~~forum~~meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial ~~condition.~~condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and OE, and the Davis-Besse extended outage (OE has no interest in Davis-Besse), have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

7480

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above ~~matter,~~matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13,”Accounting for Purchases and Sales of Inventory with the Same Counterparty”

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, OE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

EITF Issue No. 05-6, “Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination”

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with the OE current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, OE will adopt this Interpretation in the fourth quarter of 2005. OE is currently evaluating the effect this standard will have on its financial statements.

81

SFAS 154 - ~~"Accounting~~“Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate ~~effected~~affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. OE will adopt this Statement effective January 1, 2006.

~~FIN 47, "Accounting for Conditional Asset Retirement Obligations~~SFAS 153, “Exchanges of Nonmonetary Assets - an ~~interpretation~~amendment of ~~FASB Statement~~APB Opinion No. ~~143"~~29”

~~On March 30, 2005,~~In December 2004, the FASB issued ~~FIN 47 to clarify~~SFAS 153 amending APB 29, which was based on the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligationprinciple that ~~is conditional~~nonmonetary assets should be measured based on ~~a future event, if~~ the fair value of the ~~liability can be reasonably estimated. In instances where there is insufficient information~~assets exchanged. The guidance in APB 29 included certain exceptions to ~~estimate~~that principle. SFAS 153 eliminates the ~~liability,~~exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the ~~obligation is~~future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore,applied prospectively. As a result, OE will adopt this ~~Interpretation in the fourth quarter of 2005. OE is currently evaluating the effect this standard will~~Statement effective January 1, 2006, and does not expect it to have a material impact on its financial statements.

~~EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"~~SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In ~~March~~November 2004, the ~~EITF reached a consensus~~FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the ~~application guidance~~normal capacity of the production facilities. The provisions of this statement are effective for ~~Issue 03-1.~~inventory costs incurred by OE beginning January 1, 2006. OE is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”

In September 2005, the FASB finalized and renamed EITF 03-1 ~~provides~~and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a ~~model for determining~~Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when ~~investments in certain debt and equity securities are considered~~the impairment is deemed other than ~~temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value~~temporary, even if a decision to sell has not been made, and ~~the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to~~(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after ~~June~~September 15, ~~2004, were delayed indefinitely by~~2005. The FASB expects to issue this FSP in the ~~issuance~~fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. OE is currently evaluating this FSP ~~EITF 03-1-1 in September 2004. During the period of delay, OE continues to evaluate~~and any impact on its ~~investments as required by existing authoritative guidance.~~investments.

7582

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY													THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME	CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME													CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)	(Unaudited)													(Unaudited)

		Three Months Ended						Six Months Ended							Three Months Ended							Nine Months Ended
		June 30,						June 30,							September 30,							September 30,
		2005			2004			2005			2004				2005			2004				2005			2004
		*(In thousands)*													*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES		$	448,747		$	440,876		$	881,920		$	867,411			$	526,421		$	504,848		$	1,408,341		$	1,372,259

OPERATING EXPENSES AND TAXES:
Fuel			21,110			19,376			39,437			36,572				24,701			21,011			64,138			57,583
Purchased power			138,842			136,505			281,726			271,182				129,640			140,988			411,366			412,170
Nuclear operating costs			36,786			18,521			95,513			51,236				26,252			28,766			121,765			80,002
Other operating costs			74,711			79,634			138,284			143,661				89,475			76,196			227,759			219,857
Provision for depreciation			33,387			32,776			64,502			64,964				36,100			33,096			100,602			98,060
Amortization of regulatory assets			55,016			50,022			109,042			98,090				68,455			53,732			177,497			151,822
Deferral of new regulatory assets			(40,701	)		(32,956	)		(65,989	)		(51,436	)			(60,519	)		(40,596	)		(126,508	)		(92,032	)
General taxes			36,605			34,480			75,492			73,298				40,054			37,348			115,546			110,646
Income taxes			34,734			25,161			39,611			29,174				55,286			51,883			94,897			81,057
Total operating expenses and taxes			390,490			363,519			777,618			716,741				409,444			402,424			1,187,062			1,119,165

OPERATING INCOME			58,257			77,357			104,302			150,670				116,977			102,424			221,279			253,094

OTHER INCOME (net of income taxes)			9,270			9,494			13,574			21,221				24,117			8,264			37,691			29,485

NET INTEREST CHARGES:
Interest on long-term debt			28,410			36,695			56,362			68,906				27,090			24,061			83,452			92,967
Allowance for borrowed funds used during construction			(1,294	)		(1,015	)		(883	)		(2,726	)			(1,129	)		(1,056	)		(2,012	)		(3,782	)
Other interest expense			1,742			1,446			8,256			7,511				4,696			5,239			12,952			12,750
Net interest charges			28,858			37,126			63,735			73,691				30,657			28,244			94,392			101,935

NET INCOME			38,669			49,725			54,141			98,200				110,437			82,444			164,578			180,644

PREFERRED STOCK DIVIDEND REQUIREMENTS			-			1,755			2,918			3,499				-			1,754			2,918			5,253

EARNINGS ON COMMON STOCK		$	38,669		$	47,970		$	51,223		$	94,701			$	110,437		$	80,690		$	161,660		$	175,391

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME		$	38,669		$	49,725		$	54,141		$	98,200			$	110,437		$	82,444		$	164,578		$	180,644

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities			(1,349	)		(10,371	)		(2,570	)		(2,323	)
Income tax benefit related to other comprehensive income			419			4,248			923			952
Unrealized gain (loss) on available for sale securities																(6,574	)		991			(9,144	)		(1,332	)
Income tax expense (benefit) related to other comprehensive income																(2,510	)		406			(3,433	)		(546	)
Other comprehensive income (loss), net of tax			(930	)		(6,123	)		(1,647	)		(1,371	)			(4,064	)		585			(5,711	)		(786	)

TOTAL COMPREHENSIVE INCOME		$	37,739		$	43,602		$	52,494		$	96,829			$	106,373		$	83,029		$	158,867		$	179,858

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an	The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an													The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

7683

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2005		2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	4,498,876	$	4,418,313
Less - Accumulated provision for depreciation		2,020,868		1,961,737
		2,478,008		2,456,576
Construction work in progress -
Electric plant		90,911		85,258
Nuclear fuel		8,632		30,827
		99,543		116,085
		2,577,551		2,572,661
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		564,169		596,645
Nuclear plant decommissioning trusts		427,920		383,875
Long-term notes receivable from associated companies		8,774		97,489
Other		16,028		17,001
		1,016,891		1,095,010
CURRENT ASSETS:
Cash and cash equivalents		207		197
Receivables-
Customers (less accumulated provision of $5,309,000 for uncollectible accounts in 2005)		255,769		11,537
Associated companies		19,883		33,414
Other (less accumulated provisions of $6,000 and $293,000, respectively,		9,651		152,785
for uncollectible accounts)
Notes receivable from associated companies		-		521
Materials and supplies, at average cost		72,506		58,922
Prepayments and other		2,769		2,136
		360,785		259,512
DEFERRED CHARGES:
Goodwill		1,688,966		1,693,629
Regulatory assets		889,127		958,986
Property taxes		77,792		77,792
Other		29,995		32,875
		2,685,880		2,763,282
	$	6,641,107	$	6,690,465
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding	$	1,356,998	$	1,281,962
Accumulated other comprehensive income		12,148		17,859
Retained earnings		574,394		553,740
Total common stockholder's equity		1,943,540		1,853,561
Preferred stock		-		96,404
Long-term debt and other long-term obligations		1,939,730		1,970,117
		3,883,270		3,920,082
CURRENT LIABILITIES:
Currently payable long-term debt		75,706		76,701
Short-term borrowings-
Associated companies		518,784		488,633
Other		35,000		-
Accounts payable-
Associated companies		33,802		150,141
Other		6,702		9,271
Accrued taxes		156,630		129,454
Accrued interest		27,242		22,102
Lease market valuation liability		60,200		60,200
Other		39,094		61,131
		953,160		997,633
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		552,072		540,211
Accumulated deferred investment tax credits		58,736		60,901
Lease market valuation liability		623,100		668,200
Asset retirement obligation		280,765		272,123
Retirement benefits		86,597		82,306
Other		203,407		149,009
		1,804,677		1,772,750
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,641,107	$	6,690,465

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are
an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2005

2004

(In thousands)

ASSETS

UTILITY PLANT:

In service $ 4,497,877 $ 4,418,313
Less - Accumulated provision for depreciation 2,000,871 1,961,737
2,497,006 2,456,576
Construction work in progress -
Electric plant 79,897 85,258
Nuclear fuel 4,330 30,827
84,227 116,085
2,581,233 2,572,661
OTHER PROPERTY AND INVESTMENTS:

Investment in lessor notes 564,172 596,645
Nuclear plant decommissioning trusts 401,610 383,875
Long-term notes receivable from associated companies 7,546 97,489
Other 15,945 17,001
989,273 1,095,010
CURRENT ASSETS:

Cash and cash equivalents 207 197
Receivables-
Customers (less accumulated provision of $4,510,000 for uncollectible accounts in 2005) 255,422 11,537
Associated companies 29,279 33,414
Other (less accumulated provisions of $19,000 and $293,000, respectively,
for uncollectible accounts) 11,109 152,785
Notes receivable from associated companies 23,537 521
Materials and supplies, at average cost 87,713 58,922
Prepayments and other 1,948 2,136
409,215 259,512
DEFERRED CHARGES:

Goodwill 1,693,629 1,693,629
Regulatory assets 902,137 958,986
Property taxes 77,792 77,792
Other 36,471 32,875
2,710,029 2,763,282
$ 6,689,750 $ 6,690,465
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding $ 1,356,983 $ 1,281,962
Accumulated other comprehensive income 16,212 17,859
Retained earnings 480,957 553,740
Total common stockholder's equity 1,854,152 1,853,561
Preferred stock - 96,404
Long-term debt and other long-term obligations 1,948,083 1,970,117
3,802,235 3,920,082
CURRENT LIABILITIES:

Currently payable long-term debt 75,694 76,701
Short-term borrowings-
Associated companies 404,290 488,633
Other 155,000 -
Accounts payable-
Associated companies 191,959 150,141
Other 5,733 9,271
Accrued taxes 122,675 129,454
Accrued interest 21,782 22,102
Lease market valuation liability 60,200 60,200
Other 43,841 61,131
1,081,174 997,633
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 543,554 540,211
Accumulated deferred investment tax credits 58,241 60,901
Asset retirement obligation 281,206 272,123
Retirement benefits 84,428 82,306
Lease market valuation liability 638,100 668,200
Other 200,812 149,009
1,806,341 1,772,750
COMMITMENTS AND CONTINGENCIES (Note 13)

$ 6,689,750 $ 6,690,465

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are
an integral part of these balance sheets.

7784

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2005

2004

2005

2004

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 38,669 $ 49,725 $ 54,141 $ 98,200
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation 33,387 32,776 64,502 64,964
Amortization of regulatory assets 55,016 50,022 109,042 98,090
Deferral of new regulatory assets (40,701 ) (32,956 ) (65,989 ) (51,436 )
Nuclear fuel and capital lease amortization 6,171 7,509 10,781 12,616
Amortization of electric service obligation (4,672 ) (4,818 ) (10,123 ) (9,541 )
Deferred rents and lease market valuation liability (222 ) (223 ) (53,691 ) (41,858 )
Deferred income taxes and investment tax credits, net 8,956 2,412 4,450 (1,627 )
Accrued retirement benefit obligations 2,600 2,314 2,122 8,046
Accrued compensation, net 230 476 (2,495 ) 1,929
Decrease (increase) in operating assets-
Receivables (182,964 ) (33,923 ) (98,074 ) 109,843
Materials and supplies (6,455 ) (3,118 ) (28,791 ) (5,473 )
Prepayments and other current assets (439 ) 2 188 1,897
Increase (decrease) in operating liabilities-
Accounts payable (958 ) (80,735 ) 38,280 (58,348 )
Accrued taxes 14,419 31,061 (6,779 ) (36,865 )
Accrued interest (12,351 ) (7,392 ) (320 ) 847
Prepayment for electric service - education programs 67,589 - 67,589 -
Other (4,513 ) (7,070 ) (7,871 ) (36,858 )
Net cash provided from (used for) operating activities (26,238 ) 6,062 76,962 154,426

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 53,284 - 53,284 80,908
Short-term borrowings, net 88,557 101,255 58,874 -
Equity contributions from parent 75,000 - 75,000 -
Redemptions and Repayments-
Preferred stock (4,000 ) - (101,900 ) -
Long-term debt (56,600 ) (175 ) (56,930 ) (8,101 )
Short-term borrowings, net - - - (80,912 )
Dividend Payments-
Common stock (69,000 ) (90,000 ) (124,000 ) (145,000 )
Preferred stock - (1,754 ) (2,260 ) (3,498 )
Net cash provided from (used for) financing activities 87,241 9,326 (97,932 ) (156,603 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (26,561 ) (20,861 ) (60,244 ) (38,729 )
Loan repayments from (loans to) associated companies, net (23,861 ) 13,736 66,927 10,814
Investments in lessor notes 3 - 32,473 20,965
Contributions to nuclear decommissioning trusts (7,256 ) (7,256 ) (14,512 ) (14,512 )
Other (3,328 ) (1,007 ) (3,664 ) (943 )
Net cash provided from (used for) investing activities (61,003 ) (15,388 ) 20,980 (22,405 )

Net increase (decrease) in cash and cash equivalents - - 10 (24,582 )
Cash and cash equivalents at beginning of period 207 200 197 24,782
Cash and cash equivalents at end of period $ 207 $ 200 $ 207 $ 200

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	110,437		$	82,444		$	164,578		$	180,644
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		36,100			33,096			100,602			98,060
Amortization of regulatory assets		68,455			53,732			177,497			151,822
Deferral of new regulatory assets		(60,519	)		(40,596	)		(126,508	)		(92,032	)
Nuclear fuel and capital lease amortization		8,236			7,804			19,017			20,420
Amortization of electric service obligation		(2,155	)		(3,336	)		(12,278	)		(12,877	)
Deferred rents and lease market valuation liability		(13,439	)		(14,324	)		(67,130	)		(56,182	)
Deferred income taxes and investment tax credits, net		10,484			13,019			14,934			11,392
Accrued retirement benefit obligations		2,169			2,854			4,291			10,900
Accrued compensation, net		1,201			1,303			(1,294	)		3,232
Pension trust contribution		-			(31,718	)		-			(31,718	)
Decrease (increase) in operating assets-
Receivables		10,507			(3,422	)		(87,567	)		106,421
Materials and supplies		15,207			(2,238	)		(13,584	)		(7,711	)
Prepayments and other current assets		(821	)		1,512			(633	)		3,409
Increase (decrease) in operating liabilities-
Accounts payable		(157,188	)		60,237			(118,908	)		1,889
Accrued taxes		33,955			(15,630	)		27,176			(52,495	)
Accrued interest		5,460			(3,218	)		5,140			(2,371	)
Prepayment for electric service - education programs		-			-			67,589			-
Other		(18,457	)		(3,335	)		(26,328	)		(40,193	)
Net cash provided from operating activities		49,632			138,184			126,594			292,610

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		87,772			44,330			141,056			125,238
Short-term borrowings, net		-			213,682			53,369			132,770
Equity contributions from parent		-			-			75,000			-
Redemptions and Repayments-
Preferred stock		-			(1,000	)		(101,900	)		(1,000	)
Long-term debt		(90,859	)		(327,171	)		(147,789	)		(335,272	)
Short-term borrowings, net		(5,505	)		-			-			-
Dividend Payments-
Common stock		(17,000	)		-			(141,000	)		(145,000	)
Preferred stock		-			(1,755	)		(2,260	)		(5,253	)
Net cash used for financing activities		(25,592	)		(71,914	)		(123,524	)		(228,517	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,809	)		(32,238	)		(98,053	)		(70,967	)
Loan repayments from (loans to) associated companies, net		22,309			(850	)		89,236			9,964
Investments in lessor notes		3			(11,699	)		32,476			9,266
Contributions to nuclear decommissioning trusts		(7,256	)		(7,256	)		(21,768	)		(21,768	)
Other		(1,287	)		(14,227	)		(4,951	)		(15,170	)
Net cash used for investing activities		(24,040	)		(66,270	)		(3,060	)		(88,675	)

Net change in cash and cash equivalents		-			-			10			(24,582	)
Cash and cash equivalents at beginning of period		207			200			197			24,782
Cash and cash equivalents at end of period	$	207		$	200		$	207		$	200

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

7885

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of ~~June~~September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~July 29,~~November 1, 2005

7986

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI provides power directly to alternative energy suppliers under CEI’s transition plan. CEI has unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the ~~second~~third quarter of 2005 ~~decreased~~increased to ~~$39~~$110 million from ~~$48~~$81 million in the ~~second~~third quarter of 2005. Increased earnings in the third quarter of 2005 resulted primarily from higher operating revenues and lower purchased power costs, which were partially offset by higher regulatory asset amortization and higher other operating costs. For the first ~~six~~nine months of 2005, earnings on common stock decreased to ~~$51~~$162 million from ~~$95~~$175 million in the same period of 2004. ~~The decrease in~~Lower earnings ~~in both~~for the first nine months of 2005 ~~periods~~resulted primarily ~~resulted~~ from ~~increases in~~higher nuclear operating costs, ~~purchased power costs,~~higher regulatory asset amortization and other operating costs and a one-time income tax ~~charge, which~~charge; those effects were partially offset by ~~higher~~increased operating revenues ~~increased regulatory asset deferrals~~ and lower net interest charges.

Operating revenues increased by $8$22 million or ~~1.8%~~4.3% in the ~~second~~third quarter of 2005 from the same period in 2004. Higher revenues ~~for the quarter~~resulted primarily ~~resulted~~ from increases in retail generation and distribution revenues of $4$3 million and ~~$10~~$19 million, respectively, ~~partially offset by~~and a $3$5 million ~~decrease~~increase in revenues from wholesale sales. During the first ~~six~~nine months of 2005, operating revenues increased by $36 million or 2.6%, compared to the same period in ~~2004, operating revenues increased by $15 million or 1.7%.~~2004. Higher revenues ~~for the first half of 2005~~ were due to increases in retail generation and distribution revenues of ~~$10~~$13 million and $5$23 million, respectively, ~~partially offset by~~and a $3$2 million ~~reduction~~increase in revenues from wholesale sales.

Increased retail generation revenues for the ~~second~~third quarter ~~and first six months~~ of 2005 resulted from higher ~~commercial and~~ industrial unit prices and higher residential KWH sales, partially offset by lower ~~industrial~~unit prices and KWH ~~sales. A 16.8%~~sales for commercial customers. An 18.7% increase in residential KWH sales during the ~~second~~third quarter was primarily due to warmer weather in CEI's service area, as compared to last year. AAn increase in residential customer shopping by 1.7 percentage points in the third quarter of 2005 partially offset the higher generation KWH sales as compared to 2004. Increased retail generation revenues for the first nine months of 2005 resulted from higher industrial unit prices and higher residential KWH sales, partially offset by lower commercial and industrial KWH sales. The decrease in residential customer shopping by ~~4.1 percentage points in the second quarter and 2.1~~0.7 percentage points in the first ~~six~~nine months of 2005 ~~also~~ contributed slightly to the higher generation KWH sales for ~~each~~the period as compared to ~~2004.~~last year.

Revenue from wholesale sales ~~decreased~~increased by $3$5 million during the ~~second~~third quarter of 2005, reflecting the effect of a ~~7.5% net decrease~~2.5% increase in KWH sales. The increase in wholesale sales was primarily due to a 13.6% KWH increase in MSG sales to non-affiliated wholesale customers ($3.5 million). Under its Ohio transition plan, CEI is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters). ~~Sales to FES decreased by $12 million (10.6% KWH decrease) due to a decrease in nuclear generation available for sale. The decrease in~~Increased sales to FES ~~was partially offset by a $9~~of $1.5 million ~~increase in MSG sales to non-affiliated wholesale customers (29.7%~~(1.3% KWH increase) ~~during~~also contributed to the ~~second~~third quarter ~~of 2005.~~results. In the first ~~six~~nine months of 2005, wholesale sales revenue ~~decreased~~increased by ~~$3 million, reflecting the effect of a 5.4% net decrease in KWH sales.~~$2 million. A ~~decrease in sales to FES of~~ $20 million ~~(8.9% KWH decrease) was partially offset by a $17 million~~ increase ~~(33.9%~~(23.0% KWH increase) in MSG sales to non-affiliated wholesale ~~customers.~~customers was partially offset by an $18 million decrease in sales (6.7% KWH decrease) to FES.

Revenues from distribution throughput increased ~~$10~~$19 million in the ~~second~~third quarter of 2005 compared with the same quarter of 2004. The increase was due to higher residential and ~~commercial~~industrial revenues ($1318 million and $3$5 million, respectively), reflecting increased distribution deliveries in the ~~second~~third quarter of 2005, in part due to warmer weather. These increases were partially offset by lower ~~industrial~~commercial revenues of $6$4 million as a result of lower unit ~~prices and decreases in KWH sales.~~prices.

Revenues from distribution throughput increased $5$23 million in the first ~~six~~nine months of 2005 compared with the same period in 2004 due to higher revenues in the residential sector ($928 million) ~~and commercial ($5 million) sectors,~~, partially offset by lower industrial revenues ($94 million). Higher distribution deliveries in the residential ~~and commercial sectors~~sector were partially offset by lower unit prices and ~~decreases in~~decreased KWH ~~sales~~deliveries to industrial customers. Revenues in the ~~industrial sector.~~commercial sector increased slightly ($0.4 million) as higher distribution deliveries were almost totally offset by lower unit prices.

Changes in ~~electric generation~~KWH sales ~~and distribution deliveries~~by customer class in the ~~second quarter~~three months and ~~first six~~nine months ofended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

Three

Six

Changes in KWH Sales

Months

Months

Increase (Decrease)

Electric Generation:
Retail (0.9 )% (0.8 )%
Wholesale (7.5 )% (5.4 )%
Total Electric Generation Sales

(4.8
)%

(3.4
)%

Distribution Deliveries:
Residential 16.8 % 5.0 %
Commercial 3.1 % 4.3 %
Industrial (3.4 )% (2.9 )%
Total Distribution Deliveries

3.0
%

1.0
%

Operating Expenses and Taxes

Total operating expenses and taxes increased by ~~$27~~$7 million in the ~~second~~third quarter and ~~$61~~$68 million in the first ~~six~~nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the ~~second~~third quarter of 2005 was ~~2.93%~~3.50%.

CEI’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. ~~The ratings outlook from the rating agencies on all such securities is positive.~~

On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in ~~its~~their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

83

Cash Flows from Investing Activities

In the ~~second~~third quarter and first nine months of 2005, net cash used for investing activities ~~increased $46~~decreased $42 million and $86 million, respectively, from the ~~second quarter~~corresponding periods of 2004. The ~~increase~~decrease in funds used for investing activities for both periods primarily reflected increased property additions and an increase in loans to associated companies. The $43 million increase in net cash provided from investing activities for the first six months of 2005 as compared to the same period last year was primarily due to increases in loan payments received from associated companies, partially offset by increased property additions.

~~During~~In the ~~second half~~last quarter of 2005, capital requirements for property additions are expected to be about ~~$68 million, including $4 million for nuclear fuel.~~$37 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI has no additional requirements for sinking fund requirements for preferred stock and debt during the remainder of 2005.

CEI’s capital spending for the period 2005-2007 is expected to be about $368 million ~~(excluding nuclear fuel)~~ of which approximately ~~$118~~$124 million applies to 2005. ~~Investments for additional~~

FirstEnergy Intra-System Generation Asset Transfers

On May 18, 2005, OE, CEI and TE, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear ~~fuel during~~and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include CEI’s leasehold interests in certain of the ~~2005-2007 period~~plants that are ~~estimated~~currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, CEI completed the transfer of non-nuclear generation assets to FGCO. CEI currently expects to complete the transfer of nuclear generation assets to NGC at book value before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be ~~approximately $79 million,~~separated from the regulated delivery business of ~~which about $13 million applies~~those companies through transfer to ~~2005. During~~a separate corporate entity. FENOC currently operates and maintains the ~~same periods, CEI’s~~ nuclear ~~fuel investments are expected~~generation assets to be ~~reduced~~transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by ~~approximately $91 million~~the restructuring plans by transferring the ownership interests to NGC and ~~$27 million,~~FGCO, respectively, aswithout impacting the ~~nuclear fuel is consumed.~~operation of the plants.

See Note 17 to the consolidated financial statements for CEI’s disclosure of the assets held for sale as of September 30, 2005.

· Maintain the existing level of base distribution rates through April 30, 2009 for CEI;

· Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during the

period January 1, ~~2006. The~~2006 through December 31, 2008, not to exceed $150 million in each of the three

years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized

costs will occur as of December 31, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI

by accelerating the application of its accumulated cost of removal regulatory liability; and

· Defer and capitalize all of CEI's allowable fuel cost increases until January 1, 2009.

Under provisions of the RSP, the PUCO may require CEI to undertake, no more often than annually, a ~~similar~~ competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for CEI in ~~2004.~~2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the ~~Rate Stabilization Plan~~RSP pricing, ~~but not~~with no accounting impacts to the ~~related approved accounting,~~RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $16 million per year; however, CEI anticipates that this amount will increase. CEI requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted ~~thereafter~~ each July 1.1 thereafter. CEI reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by CEI, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. IfThe PUCO approved the settlement stipulation ~~is approved by the PUCO, the actual amounts~~on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $23.9 million. This value includes the ~~January 1,~~recovery of the 2005 deferred MISO expenses as described below. In May 2006, ~~rider~~CEI will ~~be submitted~~file a modification to the ~~PUCO on or before November 1, 2005.~~rider which will determine revenues from July 2006 through June 2007.

85

The second application ~~seeks~~sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in ~~the~~ MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. ~~Deferral of all~~Permission to defer costs incurred prior to December ~~31,~~30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, ~~is pending.~~was approved in a PUCO order issued on August 31, 2005, approving the stipulation referred to above. The OCC, OPAE and CEI each filed applications for rehearing. CEI sought authority to defer the transmission and ancillary ~~service related~~service-related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied ~~CEI's~~CEI’s and OCC’s applications and, at the request of CEI, struck as untimely OPAE’s application. ~~CEI and the~~The OCC ~~have sixty days from that date to file~~filed a notice of appeal with the Ohio Supreme ~~Court.~~ Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

~~On September 16, 2004, the FERC issued an order that imposed additional obligations on~~ CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. On April 15, 2005, FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market, which became effective April 1, 2005. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.

~~Regulatory~~records as regulatory assets ~~are~~ costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. CEI's regulatory assets as of ~~June~~September 30, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total ~~$354~~$402 million as of ~~June~~September 30, 2005 and under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. ~~Recovery of~~See Note 14 “Regulatory Matters - Ohio” for the ~~new regulatory assets will begin at that time and~~estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the ~~regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.~~proposed RCP and current RSP.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

CEI accrues environmental liabilities only when it concludes that it is probable that ~~it has~~they have an obligation for such costs and can reasonably ~~determine~~estimate the amount of such costs. Unasserted claims are reflected in ~~CEI's~~CEI’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report ~~that will disclose the Companies’ environmental activities, including their plans~~regarding its response to ~~respond to environmental~~air emission requirements. FirstEnergy expects to complete the report by December 1, ~~2005 and will post the report on its web site,~~ ~~www.firstenergycorp.com~~.2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~will require~~provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). in all cases from the 2003 levels. CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_x emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which CEI operates affected facilities.

86

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions ~~in two phases~~ from coal-fired power ~~plants.~~plants in two phases. Initially, mercury emissions will ~~decline~~be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. ~~The future~~However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made ~~greenhouse gases~~GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic ~~greenhouse gas~~GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

CEI cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by CEI is lower than many regional competitors due to CEI's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

CEI has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~June~~September 30, 2005, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in ~~Current~~Other Noncurrent Liabilities are accrued liabilities aggregating approximately $2.3 million as of ~~June~~September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to CEI's normal business operations pending against CEI and its subsidiaries. The ~~most significant~~other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages ~~concluded,~~concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report ~~concludes,~~concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 ~~"recommendations~~“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of ~~June~~September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

87

~~Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking~~FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to ~~represent customers who allegedly suffered damages as a result of~~ the August 14, 2003 power ~~outages. All three~~outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. ~~Two of these~~In both such cases ~~were refiled at~~ the ~~PUCO, one in 2004 and another in 2005. In each,~~ individual complainants—three in one case and four in the other—~~seek damages related to the outages and also seek~~sought to represent others as part of a class action. ~~FirstEnergy has filed responsive pleadings to both cases.~~ The PUCO ~~has~~ dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. ~~Both~~Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insureds. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are ~~otherwise currently pending further proceedings.~~not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to ~~the two~~these six cases, ~~that were refiled at the PUCO,~~ the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. ~~FirstEnergy filed a~~FirstEnergy's motion to dismiss ~~with~~ the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on ~~October 22, 2004.~~or about December 1, 2005. No ~~timetable for a decision on the motion to dismiss has been established by the Court. No damage~~ estimate ~~has been provided and thus~~of potential liability has ~~not~~ been ~~determined.~~undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. ~~On July 8,~~CEI accrued $1.0 million for a potential fine prior to 2005 ~~FENOC requested an additional 120 days to respond to the NOV. CEI has~~and accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, ~~and~~ results of ~~operations.~~operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to emergency sirens.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two ~~years.~~years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which ~~is currently owned and/or leased by OE,~~ CEI ~~TE and Penn~~has a 44.85% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which ~~will~~ include owned portions of the plant).

On April 4, 2005, the NRC held a public ~~forum~~meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" ~~and met all cornerstone objectives although~~even though it remained under ~~the~~ heightened NRC ~~oversight since August 2004.~~oversight. During the public ~~forum~~meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for CEI in the fourth quarter of 2005. CEI is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - ~~"Accounting~~“Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in ~~an income statement.~~the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate ~~effected~~affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. ~~FirstEnergy~~CEI will adopt this Statement effective January 1, 2006.

~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"~~
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

~~On March 30, 2005,~~In December 2004, the FASB issued ~~FIN 47 to clarify~~SFAS 153 amending APB 29, which was based on the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligationprinciple that ~~is conditional~~nonmonetary assets should be measured based on ~~a future event, if~~ the fair value of the ~~liability can be reasonably estimated. In instances where there is insufficient information~~assets exchanged. The guidance in APB 29 included certain exceptions to ~~estimate~~that principle. SFAS 153 eliminates the ~~liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the~~exception from fair value ~~cannot~~measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for CEI. This FSP is not expected to have a material impact on CEI’s financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be ~~reasonably estimated,~~“so abnormal” that ~~fact and~~they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the ~~reasons why must~~cost of conversion be ~~disclosed. This Interpretation is~~based on the normal capacity of the production facilities. The provisions of this statement are effective ~~no later than the end of fiscal years ending after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy~~for inventory costs incurred by CEI beginning January 1, 2006. CEI is currently evaluating ~~the effect~~ this ~~Interpretation will~~Standard and does not expect it to have a material impact on its financial statements.

89

~~EITF Issue No. 03-1,~~FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In ~~March 2004,~~September 2005, the ~~EITF reached a consensus on the application guidance for Issue 03-1.~~FASB finalized and renamed EITF 03-1 ~~provides~~and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a ~~model for determining~~Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when ~~investments in certain debt and equity securities are considered~~the impairment is deemed other than ~~temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value~~temporary, even if a decision to sell has not been made, and ~~the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to~~(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after ~~June~~September 15, ~~2004, were delayed indefinitely by~~2005. The FASB expects to issue this FSP in the ~~issuance~~fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. CEI is currently evaluating this FSP ~~EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues to evaluate~~and any impact on its ~~investments as required by existing authoritative guidance.~~investments.

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE provides power directly to some alternative energy suppliers under TE’s transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. TE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the ~~second~~third quarter of 2005 ~~decreased~~increased to $5$41 million from ~~earnings of $19~~$22 million in the ~~second~~third quarter of 2004. The increase in earnings resulted primarily from higher operating revenues and other income, partially offset by increased financing costs. Earnings on common stock in the first ~~six~~nine months of 2005 decreased to $4$44 million from ~~$25~~$47 million in the first ~~six~~nine months of 2004. The decrease in earnings ~~in both periods of 2005~~ resulted ~~principally~~primarily from higher nuclear operating costs and a one-time income tax charge, partially offset by higher operating revenues and lower financing ~~costs compared to the same period of 2004.~~costs.

Operating revenues increased by ~~$16~~$11 million, or ~~6.5%~~3.8%, in the ~~second~~third quarter of 2005 compared to the ~~second~~third quarter of 2004. Higher revenues in the ~~second~~third quarter of 2005 resulted from increased retail generation ~~sales~~ revenues of ~~$11~~$13 million and distribution revenues of $4$2 million, ~~and~~partially offset by a decrease in wholesales sales (primarily to FES) of $2$4 million ~~partially offset by~~and an increase in shopping incentive credits of $1 million. Retail generation ~~sales~~ revenues increased as a result of increased KWH sales (residential - $1 million, commercial - $2$1 million and industrial - $8$11 million). Higher residential and commercial revenues reflected increased KWH sales ~~(24.5%~~(8.0% and ~~23.2%~~9.2%, respectively)~~, partially offset by lower~~ and higher unit prices. ~~Residential~~KWH sales to residential and commercial ~~sales volumes~~customers increased primarily due to warmer weather which increased air-conditioning loads. Additionally, generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales delivered in TE’s service ~~area. The commercial generation sales volume increase also reflects a reduction~~area decreased by ~~4.7~~2.1 percentage points ~~in customer shopping~~ compared with the ~~second~~third quarter of 2004. Industrial revenues increased as a result of higher unit prices ~~partially offset by~~and a ~~3.9% decrease~~4.2% increase in KWH sales.

Revenues from distribution throughput increased by $4$2 million in the ~~second~~third quarter of 2005 from the corresponding quarter of 2004. The increase was due to higher residential and commercial revenues ($98 million and $4$0.2 million, respectively), partially offset by a decrease in industrial revenues ($97 million). The impact of higher residential and commercial KWH sales contributed to the ~~increase and offset the~~increase; lower industrial unit prices more than offset an increase in KWH sales ~~volume and unit prices.~~to industrial customers.

Operating revenues increased by ~~$22~~$33 million, or ~~4.6%~~4.3%, in the first ~~six~~nine months of 2005 compared to the same period of 2004. ~~Higher~~The higher revenues ~~in the first six months of 2005~~ resulted ~~primarily~~ from increased retail generation ~~sales~~ revenues of ~~$21~~$35 million and wholesales sales ~~(primarily to FES)~~ of $5$2 million, partially offset by ~~a decrease~~an increase in ~~distribution revenues~~shopping incentive credits of $2$3 million. Retail generation ~~sales~~ revenues increased as a result of higher KWH sales ~~in all customer sectors~~ (residential - $1$2 million, commercial - $3$4 million, industrial - ~~$17~~$29 million). ~~Increases in~~Higher residential and commercial revenues reflected increased KWH sales ~~(6.3%~~(6.9% and ~~13.9%~~12.2%, respectively) and higher unit prices. Residential and commercial sales volumes increased primarily due to warmer ~~weather, partially offset~~weather. The increase in commercial revenues also reflects a reduction by ~~lower unit prices. The higher industrial~~2.5 percentage points in customer shopping compared with the same period of 2004. Industrial revenues ~~resulted primarily from~~increased as a result of higher unit ~~prices.~~prices and a 0.6% increase in KWH sales.

Revenues from distribution throughput decreased by $2$0.4 million in the first ~~six~~nine months of 2005 ~~compared to~~from the same period in ~~2004 as a result of~~2004. The decrease was due to lower industrial ~~KWH sales and reduced unit prices, which~~revenues ($22 million), partially offset by increases in ~~KWH sales to~~ residential and commercial ~~customers.~~revenues ($15 million and $6 million, respectively). The impact from lower industrial unit prices more than offset the higher KWH sales in all customer classes.

Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $1 million from additional credits in the ~~second~~third quarter and $2$3 million in the first ~~six~~nine months of 2005 compared with the same periods of 2004. These revenue reductions are deferred for future recovery under TE’s transition plan and do not affect current period earnings (see Regulatory Matters below).

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3491	PENNSYLVANIA POWER COMPANY	25-0718810
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

YesX	No	FirstEnergy Corp.
Yes	NoX	Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF ~~AUGUST 1,~~NOVEMBER 2, 2005
FirstEnergy Corp., $.10 par value	329,836,276
Ohio Edison Company, no par value	100
The Cleveland Electric Illuminating Company, no par value	79,590,689
The Toledo Edison Company, $5 par value	39,133,887
Pennsylvania Power Company, $30 par value	6,290,000
Jersey Central Power & Light Company, $10 par value	15,371,270
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	5,290,596

		Pages
Glossary of Terms		~~iii-iv~~iii-v

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of of Results of Operation and Financial Condition

	Notes to Consolidated Financial Statements	~~1-23~~1-25

FirstEnergy Corp.

	Consolidated Statements of Income	2426
	Consolidated Statements of Comprehensive Income	2527
	Consolidated Balance Sheets	2628
	Consolidated Statements of Cash Flows	2729
	Report of Independent Registered Public Accounting Firm	2830
	Management's Discussion and Analysis of Results of Operations and	~~29-60~~31-65
	Financial Condition

Ohio Edison Company

	Consolidated Statements of Income and Comprehensive Income	6166
	Consolidated Balance Sheets	6267
	Consolidated Statements of Cash Flows	6368
	Report of Independent Registered Public Accounting Firm	6469
	Management's Discussion and Analysis of Results of Operations and	~~65-75~~70-82
	Financial Condition

The Cleveland Electric Illuminating Company

	Consolidated Statements of Income and Comprehensive Income	7683
	Consolidated Balance Sheets	7784
	Consolidated Statements of Cash Flows	7885
	Report of Independent Registered Public Accounting Firm	7986
	Management's Discussion and Analysis of Results of Operations and	~~80-90~~87-98
	Financial Condition

The Toledo Edison Company

	Consolidated Statements of Income and Comprehensive Income	9199
	Consolidated Balance Sheets	92100
	Consolidated Statements of Cash Flows	93101
	Report of Independent Registered Public Accounting Firm	94102
	Management's Discussion and Analysis of Results of Operations and	~~95-104~~103-114
	Financial Condition

Pennsylvania Power Company

	Consolidated Statements of Income and Comprehensive Income	~~105~~115
	Consolidated Balance Sheets	~~106~~116
	Consolidated Statements of Cash Flows	~~107~~117
	Report of Independent Registered Public Accounting Firm	~~108~~118
	Management's Discussion and Analysis of Results of Operations and	~~109-116~~119-127
	Financial Condition

		Pages


Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	~~117~~128
	Consolidated Balance Sheets	~~118~~129
	Consolidated Statements of Cash Flows	~~119~~130
	Report of Independent Registered Public Accounting Firm	~~120~~131
	Management's Discussion and Analysis of Results of Operations and	~~121-128~~132-140
	Financial Condition

Metropolitan Edison Company

	Consolidated Statements of Income and Comprehensive Income	~~129~~141
	Consolidated Balance Sheets	~~130~~142
	Consolidated Statements of Cash Flows	~~131~~143
	Report of Independent Registered Public Accounting Firm	~~132~~144
	Management's Discussion and Analysis of Results of Operations and	~~133-139~~145-153
	Financial Condition

Pennsylvania Electric Company

	Consolidated Statements of Income and Comprehensive Income	~~140~~154
	Consolidated Balance Sheets	~~141~~155
	Consolidated Statements of Cash Flows	~~142~~156
	Report of Independent Registered Public Accounting Firm	~~143~~157
	Management's Discussion and Analysis of Results of Operations and	~~144-150~~158-166
	Financial Condition

Item 3. Quantitative and Qualitative Disclosures About Market Risk		~~151~~167

Item 4. Controls and Procedures		~~151~~167

Part II. Other Information

Item 1. Legal Proceedings		~~152~~168
		168
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		~~152~~

Item 4.5. Other Information~~Submission of Matters to a Vote of Security Holders~~		~~152~~ 168

Item 6. Exhibits		~~153-168~~169-184

ATSI	American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CFC	Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
EUOC	Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates ~~nonnuclear~~non-nuclear generating facilities
FirstCom	First Communications, LLC, provides local and long-distance telephone service
FirstEnergy	FirstEnergy Corp., a registered public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation,
	air conditioning and energy management companies
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
	November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp. established to acquire FirstEnergy's nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
OE Companies	OE and Penn
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	~~Termobarranguilla~~Termobarranquilla S. A., Empresa de Servicios Publicos

AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 25	APB Opinion No. 25, "Accounting for Stock Issued to Employees"
APB 29	APB Opinion No. 29, ~~"Accounting~~“Accounting for Nonmonetary ~~Transactions"~~Transactions”
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAT	Commercial Activity Tax
CO₂	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain
	~~Investments"~~Investments”
EITF 04-13	EITF Issue No. 04-13, ~~"Accounting~~“Accounting for Purchases and Sales of Inventory with the Same ~~Counterparty"~~Counterparty”
EITF 99-19	EITF Issue No. 99-19, ~~"Reporting~~“Reporting Revenue Gross as a Principal versus Net as an ~~Agent"~~Agent”
EPA	Environmental Protection Agency
ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"

FIN 47	FASB Interpretation 47, ~~"Accounting~~“Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. ~~143"~~143”
~~FMB~~FMBs	First Mortgage Bonds
FSP	FASB Staff Position

FSP EITF 03-1-1	FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue
	No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
	Investments"
FSP 109-1	FASB Staff Position No. 109-1, ~~"Application~~“Application of FASB Statement No. 109, Accounting for Income
	Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs
	Creation Act of ~~2004"~~2004”
GCAF	Generation Charge Adjustment Factor
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
HVAC	Heating, Ventilation and Air-conditioning
IBEW	International Brotherhood of Electrical Workers
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
MOU	Memorandum of Understanding
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
NO_X^x	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
OCA	Office of Consumer Advocate
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPAE	Ohio Partners for Affordable Energy
OPEB	Other Post-Employment Benefits
OSBA	Office of Small Business Advocate
OTS	Office of Trial Staff
PCAOB	Public Company Accounting Oversight Board (United States)
PCRBs	Pollution Control Revenue Bonds
PICA	Penelec Industrial Customer Association
PJM	PJM Interconnection, L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Purchase and Sale Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 123	SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 123(R)	SFAS No. 123 (revised 2004), ~~"Share-Based Payment"~~“Share-Based Payment”
SFAS 131	SFAS No. 131, ~~"Disclosures~~“Disclosures about Segments of an Enterprise and Related ~~Information"~~Information”
SFAS 133	SFAS No. 133, ~~"Accounting~~“Accounting for Derivative Instruments and Hedging ~~Activities"~~Activities”
SFAS 140	SFAS No. 140, ~~"Accounting~~“Accounting for Transfers and Servicing of Financial Assets and
	Extinguishment of ~~Liabilities"~~Liabilities”
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 153	SFAS No. 153, ~~"Exchanges~~“Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. ~~29"~~29”


SFAS 154	SFAS No. 154, ~~"Accounting~~“Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"3”
SO₂	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
UWUA	Utility Workers Union of America
VIE	Variable Interest Entity

OE	$	36.0
CEI		7.5
TE		17.5
Other FirstEnergy subsidiaries		10.7
Total FirstEnergy	$	71.7

			Three Months Ended			Nine Months Ended
			September 30, 2005			September 30, 2005
			*(In millions)*

OE	$	4.9	$	1.6		$	6.5
CEI		1.4		(3.1	)		(1.7	)
TE		0.5		0.7			1.2
Other FirstEnergy subsidiaries		0.8		0.7			1.5
Total FirstEnergy	$	7.6	$	(0.1	)	$	7.5

			Financing Arrangement
Subsidiary Company	Parent Company		Borrowing Capacity
				*(In millions)*
OES Capital, Incorporated		OE	$		170
CFC		CEI			200
Penn Power Funding LLC		Penn			25
Met-Ed Funding LLC		Met-Ed			80
Penelec Funding LLC		Penelec			75
			$		550

	Estimated Net Amortization
	RCP								RSP
Amortization							Total								Total
Period	OE		CEI		TE		Ohio		OE		CEI		TE		Ohio
	*(In millions)*

2006	$	169	$	100	$	80	$	349	$	175	$	94	$	73	$	342
2007		176		111		89		376		237		104		82		423
2008		198		129		100		427		206		122		159		487
2009		-		216		-		216		-		318		-		318
2010		-		268		-		268		-		271		-		271
Net Amortization*	$	543	$	824	$	269	$	1,636	$	618	$	909	$	314	$	1,841

* RCP aggregate amortization is less than amortization under the RSP due to the accelerated application of regulatory liabilities to reduce deferred shopping incentives.

Segment Financial Information

			Power
			Supply
	Regulated		Management			Facilities						Reconciling
	Services		Services			Services			Other			Adjustments			Consolidated
	*(In millions)*
Three Months Ended:

June 30, 2005
External revenues	$	1,351	$	1,379		$	56		$	137		$	6		$	2,929
Internal revenues		80		-			-			-			(80	)		-
Total revenues		1,431		1,379			56			137			(74	)		2,929
Depreciation and amortization		322		7			-			-			6			335
Net interest charges		99		8			1			2			51			161
Income taxes		186		7			3			4			41			241
Income before discontinued operations		267		11			(3	)		6			(102	)		179
Discontinued operations		-		-			-			(1	)		-			(1	)
Net income		267		11			(3	)		5			(102	)		178
Total assets		28,454		1,601			78			512			566			31,211
Total goodwill		5,946		24			-			63			-			6,033
Property additions		158		66			-			2			7			233

June 30, 2004
External revenues	$	1,278	$	1,550		$	50		$	119		$	(5	)	$	2,992
Internal revenues		80		-			-			-			(80	)		-
Total revenues		1,358		1,550			50			119			(85	)		2,992
Depreciation and amortization		330		9			-			-			10			349
Net interest charges		113		10			-			1			56			180
Income taxes		171		26			-			(22	)		2			177
Income before discontinued operations		234		37			-			36			(105	)		202
Discontinued operations		-		-			1			1			-			2
Net income		234		37			1			37			(105	)		204
Total assets		29,101		1,475			174			604			656			32,010
Total goodwill		5,965		24			37			75			-			6,101
Property additions		129		58			1			1			7			196


Six Months Ended:

June 30, 2005
External revenues	$	2,690	$	2,673		$	102		$	247		$	18		$	5,730
Internal revenues		158		-			-			-			(158	)		-
Total revenues		2,848		2,673			102			247			(140	)		5,730
Depreciation and amortization		698		17			-			1			13			729
Net interest charges		197		18			1			3			113			332
Income taxes		341		(17	)		2			11			26			363
Income before discontinued operations		490		(25	)		(5	)		11			(151	)		320
Discontinued operations		-		-			13			5			-			18
Net income		490		(25	)		8			16			(151	)		338
Total assets		28,454		1,601			78			512			566			31,211
Total goodwill		5,946		24			-			63			-			6,033
Property additions		299		147			1			4			11			462

June 30, 2004
External revenues	$	2,568	$	3,072		$	95		$	234		$	6		$	5,975
Internal revenues		159		-			-			-			(159	)		-
Total revenues		2,727		3,072			95			234			(153	)		5,975
Depreciation and amortization		722		17			1			-			20			760
Net interest charges		219		21			-			2			109			351
Income taxes		316		25			(1	)		(18	)		(30	)		292
Income before discontinued operations		446		36			(2	)		41			(147	)		374
Discontinued operations		-		-			2			2			-			4
Net income		446		36			-			43			(147	)		378
Total assets		29,101		1,475			174			604			656			32,010
Total goodwill		5,965		24			37			75			-			6,101
Property additions		220		102			2			-			11			335

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of
interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues, which are reflected as reductions
to expenses for internal management reporting purposes, the impact from the phase-out of the State of Ohio income tax and elimination of intersegment transactions.

	Three Months Ended					Six Months Ended					Three Months Ended					Nine Months Ended
	June 30,					June 30,					September 30,					September 30,
Pension Benefit Cost (Credit)	2005			2004		2005			2004
Pension Benefits (Credit)											2005			2004		2005			2004
	*(In millions)*										*(In millions)*

OE	$	0.2		$	1.8	$	0.4		$	3.5	$	0.2		$	1.7	$	0.7		$	5.2
Penn		(0.2	)		0.1		(0.4	)		0.2		(0.2	)		0.1		(0.7	)		0.4
CEI		0.3			1.6		0.7			3.2		0.3			1.6		1.0			4.8
TE		0.3			0.8		0.6			1.6		0.3			0.8		1.0			2.3
JCP&L		(0.3	)		1.9		(0.5	)		3.7		(0.3	)		1.9		(0.8	)		5.6
Met-Ed		(1.1	)		-		(2.2	)		0.1		(1.1	)		0.1		(3.2	)		0.2
Penelec		(1.3	)		0.1		(2.7	)		0.2		(1.3	)		0.1		(4.0	)		0.4

Nine Months Ended:

September 30, 2005
External revenues	$	4,366	$	4,346		$	161		$	385		$	19		$	9,277
Internal revenues		237		-			-			-			(237	)		-
Total revenues		4,603		4,346			161			385			(218	)		9,277
Depreciation and amortization		1,076		26			-			2			19			1,123
Net interest charges		285		29			1			4			170			489
Income taxes		595		(10	)		3			13			(2	)		599
Income before discontinued operations		856		(15	)		(6	)		18			(201	)		652
Discontinued operations		-		-			13			5			-			18
Net income (loss)		856		(15	)		7			23			(201	)		670
Total assets		28,385		1,741			82			522			644			31,374
Total goodwill		5,938		24			-			62			-			6,024
Property additions		506		226			1			5			18			756

September 30, 2004
External revenues	$	4,049	$	4,828		$	156		$	324		$	4		$	9,361
Internal revenues		239		-			-			-			(239	)		-
Total revenues		4,288		4,828			156			324			(235	)		9,361
Depreciation and amortization		1,098		26			1			-			28			1,153
Net interest charges		301		30			-			2			169			502
Income taxes		541		55			(1	)		(19	)		(70	)		506
Income before discontinued operations		761		79			(1	)		39			(207	)		671
Discontinued operations		-		-			3			3			-			6
Net income (loss)		761		79			2			42			(207	)		677
Total assets		28,416		1,467			182			596			564			31,225
Total goodwill		5,965		24			37			75			-			6,101
Property additions		377		149			2			1			17			546

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily
consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues, which are
reflected as reductions to expenses for internal management reporting purposes, and elimination of intersegment transactions.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands, except per share amounts)*
REVENUES:
Electric utilities	$	2,329,795		$	2,170,570		$	4,638,311		$	4,347,603
Unregulated businesses (Note 2)		599,483			821,592			1,091,686			1,627,462
Total revenues		2,929,278			2,992,162			5,729,997			5,975,065

EXPENSES:
Fuel and purchased power (Note 2)		932,596			1,095,135			1,827,928			2,229,461
Other operating expenses		912,592			832,398			1,805,587			1,631,742
Provision for depreciation		149,025			146,155			291,657			291,965
Amortization of regulatory assets		306,572			270,986			617,413			581,188
Deferral of new regulatory assets		(120,162	)		(68,315	)		(179,669	)		(112,720	)
General taxes		167,865			157,732			353,044			336,722
Total expenses		2,348,488			2,434,091			4,715,960			4,958,358

INCOME BEFORE INTEREST AND INCOME TAXES		580,790			558,071			1,014,037			1,016,707

NET INTEREST CHARGES:
Interest expense		161,714			179,542			326,358			352,048
Capitalized interest		(4,697	)		(5,280	)		(4,952	)		(11,750	)
Subsidiaries’ preferred stock dividends		3,733			5,389			10,286			10,670
Net interest charges		160,750			179,651			331,692			350,968

INCOME TAXES		241,275			176,560			362,550			291,530

INCOME BEFORE DISCONTINUED OPERATIONS		178,765			201,860			319,795			374,209

Discontinued operations (net of income taxes (benefit) of
$(1,282,000) and $993,000 in the three months ended
June 30, and $(9,051,000) and $2,137,000 in the six
months ended June 30, of 2005 and 2004, respectively)
(Note 6)		(773	)		2,185			17,923			3,835

NET INCOME	$	177,992		$	204,045		$	337,718		$	378,044

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	0.54		$	0.61		$	0.98		$	1.15
Discontinued operations (Note 6)		-			0.01			0.05			0.01
Net earnings per basic share	$	0.54		$	0.62		$	1.03		$	1.16

WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING		328,063			327,284			327,986			327,171

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	0.54		$	0.61		$	0.97		$	1.14
Discontinued operations (Note 6)		-			0.01			0.05			0.01
Net earnings per diluted share	$	0.54		$	0.62		$	1.02		$	1.15

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING		329,879			329,103			329,679			329,061

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.4125		$	0.375		$	0.825		$	0.75

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

NET INCOME	$	177,992		$	204,045		$	337,718		$	378,044

OTHER COMPREHENSIVE (LOSS) INCOME:
Unrealized gain (loss) on derivative hedges		(6,023	)		19,244			1,300			20,609
Unrealized loss on available for sale securities		(16,137	)		(19,122	)		(24,123	)		(2,193	)
Other comprehensive (loss) income		(22,160	)		122			(22,823	)		18,416
Income tax expense (benefit) related to other
comprehensive income		5,778			(314	)		5,907			(9,785	)
Other comprehensive (loss) income, net of tax		(16,382	)		(192	)		(16,916	)		8,631

COMPREHENSIVE INCOME	$	161,610		$	203,853		$	320,802		$	386,675


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

Reconciliation of non-GAAP to GAAP	2005						2004
	After-tax			Basic			After-tax			Basic
	Amount			Earnings			Amount			Earnings
Three Months Ended September 30,	(Millions)			Per Share			(Millions)			Per Share
Earnings Before Unusual Items (Non-GAAP)	$	342		$	1.04		$	319		$	0.97
Unusual Items:
Non-core asset sales gains/losses, net		-			-			(16	)		(0.05	)
JCP&L arbitration decision		(10	)		(0.03	)		-			-
Other		-			-			(4	)		(0.01	)
Net Income (GAAP)	$	332		$	1.01		$	299		$	0.91

Nine Months Ended September 30,
Earnings Before Unusual Items (Non-GAAP)	$	730		$	2.22		$	753		$	2.30
Unusual Items:
Non-core asset sales gains/losses, net		22			0.07			(23	)		(0.07	)
Davis-Besse impacts		-			-			(38	)		(0.12	)
EPA settlement		(14	)		(0.04	)		-			-
NRC fine		(3	)		(0.01	)		-			-
JCP&L rate settlement		16			0.05			-			-
JCP&L arbitration decision		(10	)		(0.03	)		-			-
Ohio tax write-off		(71	)		(0.22	)		-			-
Class-action lawsuit settlement		-			-			(11	)		(0.03	)
Other		-			-			(4	)		(0.01	)
Net Income (GAAP)	$	670		$	2.04		$	677		$	2.07

				Power
				Supply		Other and
2nd Quarter 2005	Regulated			Management		Reconciling			FirstEnergy
Quarterly Financial Results	Services			Services		Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	1,165		$	1,314	$	-		$	2,479
Other		186			65		199			450
Internal		80			-		(80	)		-
Total Revenues		1,431			1,379		119			2,929

Expenses:
Fuel and purchased power		-			933		-			933
Other operating		408			399		106			913
Provision for depreciation		135			7		6			148
Amortization of regulatory assets		307			-		-			307
Deferral of new regulatory assets		(120	)		-		-			(120	)
General taxes		149			14		4			167
Total Expenses		879			1,353		116			2,348

Net interest charges		99			8		54			161
Income taxes		186			7		48			241
Income before discontinued operations		267			11		(99	)		179
Discontinued operations		-			-		(1	)		(1	)
Net Income (Loss)	$	267		$	11	$	(100	)	$	178

Change Between				Power														Power
2nd Quarter 2005 and 2004				Supply			Other and
3^rd Quarter 2005 and 2004																		Supply			Other and
Quarterly Financial Results	Regulated			Management			Reconciling			FirstEnergy					Regulated			Management			Reconciling			FirstEnergy
Increase (Decrease)	Services			Services			Adjustments			Consolidated					Services			Services			Adjustments⁽¹⁾			Consolidated
	*(In millions)*														*(In millions)*
Revenue:
External
Electric	$	40		$	(206	)	$	-			$	(166	)		$	123		$	(37	)	$	--		$	86
Other		33			35			35				103				72			(7	)		51			116
Internal		-			-			-				-				(1	)		--			1			--
Total Revenues		73			(171	)		35				(63	)			194			(44	)		52			202

Expenses:
Fuel and purchased power		-			(162	)		-				(162	)			--			2			--			2
Other operating		33			44			5				82				97			8			19			124
Provision for depreciation		8			(2	)		(4	)			2				8			--			(2	)		6
Amortization of regulatory assets		36			-			-				36				40			--			--			40
Deferral of new regulatory assets		(52	)		-			-				(52	)			(45	)		--			--			(45	)
General taxes		14			(4	)		(1	)			9				9			1			--			10
Total Expenses		39			(124	)		-				(85	)			109			11			17			137

Net interest charges		(14	)		(2	)		(3	)			(19	)			6			2			(1	)		7
Income taxes		15			(19	)		68				64				28			(23	)		18			23
Income before discontinued operations		33			(26	)		(30	)			(23	)			51			(34	)		18			35
Discontinued operations		-			-			(3	)			(3	)			--			--			(2	)		(2	)
Net Income (Loss)	$	33		$	(26	)	$	(33	)		$	(26	)		$	51		$	(34	)	$	16		$	33

⁽¹⁾The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.														⁽¹⁾The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.

	~~Increase~~
Electric Distribution Deliveries	~~(Decrease)~~Increase
Residential		~~9.5~~15.4	%
Commercial		~~2.9~~7.8	%
Industrial		~~(3.8~~5.2	)%
Total Distribution Deliveries		~~2.4~~9.6	%

	Three Months Ended
	June 30,
Gross Generation Margin	2005		2004		(Decrease)
	*(In millions)*
Electric generation revenue	$	1,314	$	1,520	$	(206	)
Fuel and purchased power costs		933		1,095		(162	)
Gross generation margin	$	381	$	425	$	(44	)

	Increase
Source of Change in Electric Generation Sales	(Decrease)
	*(In millions)*
Retail:
Effect of 9.9% increase in customer usage	$	113
Change in prices		72
		185
Wholesale:
Effect of 8.7% reduction in customer usage⁽¹⁾		(41	)
Change in prices		83
		42
Net Increase in Electric Generation Sales	$	227

⁽¹⁾ Decrease of 46.4% including the effect of the PJM revision.

~~Electric Generation~~	~~Increase~~
	~~(Decrease)~~

~~Retail~~		~~2.3~~	%
~~Wholesale~~		~~(0.9~~	)%
~~Total Electric Generation~~		~~1.5~~	%*

* Decrease of 15.6% including the effect of the PJM revision.

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*
Fuel:
Change due to increased unit costs	$	92
Change due to volume consumed		29
		121
Purchased Power:
Change due to increased unit costs		130
Change due to volume purchased		(16	)
Reduction in costs deferred		31
		145
PJM gross transactions		(264	)
Net Increase in Fuel and Purchased Power Costs	$	2

				Power
Change Between Nine Months ended				Supply			Other and
September 30, 2005 vs. 2004	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments⁽¹⁾			Consolidated
Increase (Decrease)	*(In millions)*
Revenue:
External
Electric	$	171		$	(469	)	$	-		$	(298	)
Other		146			(13	)		81			214
Internal		(2	)		-			2			-
Total Revenues		315			(482	)		83			(84	)

Expenses:
Fuel and purchased power		-			(400	)		-			(400	)
Other operating		181			74			2			257
Provision for depreciation		13			-			(8	)		5
Amortization of regulatory assets		77			-			-			77
Deferral of new regulatory assets		(111	)		-			-			(111	)
General taxes		22			4			1			27
Total Expenses		182			(322	)		(5	)		(145	)

Net interest charges		(16	)		(1	)		4			(13	)
Income taxes		54			(65	)		104			93
Income before discontinued operations		95			(94	)		(20	)		(19	)
Discontinued operations		-			-			12			12
Net Income (Loss)	$	95		$	(94	)	$	(8	)	$	(7	)

⁽¹⁾ The impact of the new Ohio tax legislation is included with FirstEnergy's other operating segments and reconciling adjustments.

~~Electric Distribution Deliveries~~	~~Increase~~

~~Residential~~		~~3.8~~	%
~~Commercial~~		~~3.8~~	%
~~Industrial~~		~~0.1~~	%
~~Total Distribution Deliveries~~		~~2.5~~	%

	Three Months Ended							Nine Months Ended
Postretirement	September 30,				Increase			September 30,				Increase
Benefits Expense *	2005		2004		(Decrease)			2005		2004		(Decrease)
	*(In millions)*

Pension	$	8	$	21	$	(13	)	$	24	$	64	$	(40	)
OPEB		18		22		(4	)		54		68		(14	)
Total	$	26	$	43	$	(17	)	$	78	$	132	$	(54	)

* Excludes the capitalized portion of postretirement benefits costs (see Note 10 for total costs).

Borrowing Capability	FirstEnergy			Penelec			Total
	*(In millions)*

Short-term credit⁽¹⁾	$	2,020		$	-		$	2,020
Utilized		-			-			-
Letters of credit		(137	)		-			(137	)
Net		1,883			-			1,883

Short-term bank facilities⁽²⁾		-			75			75
Utilized		-			(75	)		(75	)
Net		-			-			-
Total unused borrowing capability	$	1,883		$	-		$	1,883

⁽¹⁾ A $2 billion revolving credit facility is available in various amounts to FirstEnergy and certain of its subsidiaries, including Penelec. A $20 million uncommitted line of credit facility added in September 2005 is available to FirstEnergy only.
⁽²⁾ Penelec bank facility terminated on October 7, 2005.

	Revolving	Regulatory and	Revolving		Regulatory and
	Credit Facility	Other Short-Term	Credit Facility		Other Short-Term
Borrower	Sub-Limit	Debt Limitations¹	Sub-Limit		Debt Limitations¹
	*(In millions)*		*(In millions)*

FirstEnergy	$2,000	$1,500	$	2,000	$	1,500
OE	500			500		500
Penn	50	49		50		51
CEI	250	500		250		500
TE	250	500		250		500
JCP&L	425	414		425		416
Met-Ed	250	250²		250		300
Penelec	250	250²		250		300
FES	-³	n/a		-²		n/a
ATSI	-³	26		-²		26

Optional Debt and Preferred Stock Redemptions by Company	Date of Redemption		Principal/Par		Annual Cost
			*(In millions)*
CEI		May 1, 2005	$	2		7.000	%
		June 1, 2005		4		7.350	%
JCP&L		May 1, 2005		6		7.125	%
		June 30, 2005		50		8.450	%
Met-Ed		May 1, 2005		7		6.000	%
Penelec		May 1, 2005		3		6.125	%
Penn		May 16, 2005		13		7.625	%
		May 16, 2005		25		7.750	%
			$	110

TE		July 1, 2005	$	30		7.000	%

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	*(In millions)*

Three Months Ended September 30, 2005
Regulated services	$	(207	)	$	(17	)	$	2		$	(222	)
Power supply management services		(79	)		1			-			(78	)
Other		(1	)		-			1			-
Reconciling items		(7	)		(9	)		5			(11	)
Total	$	(294	)	$	(25	)	$	8		$	(311	)

Three Months Ended September 30, 2004
Regulated services	$	(157	)	$	242		$	(69	)	$	16
Power supply management services		(46	)		(11	)		-			(57	)
Other		(1	)		-			(2	)		(3	)
Reconciling items		(7	)		10			84			87
Total	$	(211	)	$	241		$	13		$	43


Six Months Ended June 30, 2005
Regulated services	$	(299	)	$	4		$	(7	)	$	(302	)
Power supply management services		(147	)		(1	)		-			(148	)
Other		(5	)		19			(19	)		(5	)
Reconciling items		(11	)		-			-			(11	)
Total	$	(462	)	$	22		$	(26	)	$	(466	)

Six Months Ended June 30, 2004
Regulated services	$	(220	)	$	(46	)	$	(7	)	$	(273	)
Power supply management services		(103	)		(3	)		-			(106	)
Other		(2	)		173			4			175
Reconciling items		(10	)		53			(19	)		24
Total	$	(335	)	$	177		$	(22	)	$	(180	)

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*
FirstEnergy guarantees of subsidiaries:
Energy and energy-related contracts ⁽¹⁾	$	785
Other ⁽²⁾		503
		1,288

Surety bonds		307
Letters of credit ⁽³⁾⁽⁴⁾		1,055

Total Guarantees and Other Assurances	$	2,650

⁽¹⁾Issued for a one-year term, with a 10-day termination right by FirstEnergy.
⁽²⁾Issued for various terms.
⁽³⁾Includes $137 million issued for various terms under LOC capacity available
under FirstEnergy's revolving credit agreement and $299 million outstanding in
support of pollution control revenue bonds issued with various maturities.
⁽⁴⁾Includes approximately $194 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection
with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged
in connection with the sale and leaseback of Perry Unit 1 by OE.